8-K

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 6, 2003

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

New York (State or other jurisdiction of incorporation)	1-13515 (Commission file number)	25-0484900 (IRS 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

Item 7. Financial Statements, Pro Forma Financial Information and Exhibits.

(c)

Exhibits.

Exhibit	Description
99.1	Forest Oil Corporation press release dated August 6, 2003, entitled "Forest Oil Announces 113% Increase in Net Earnings for the Second Quarter and Reports Operational Results"

Item 9 and Item 12. Regulation FD Disclosure and Results of Operations and Financial Condition.

        The following information is furnished under Item 9. "Regulation FD Disclosure" and Item 12. "Results of Operations and Financial Condition."

        On August 6, 2003, we issued a press release with respect to our second quarter 2003 financial and operating results. The press release is furnished as Exhibit 99.1 to this Current Report and incorporated by reference herein. The press release contains a measure that may be deemed a "non-GAAP financial measure" as defined in Item 10 of Regulation S-K under the Securities Exchange Act of 1934, as amended. In this case, the most directly comparable generally accepted accounting principle (GAAP) financial measure and information reconciling the GAAP and non-GAAP financial measures is also included in the press release.

        In accordance with General Instructions B.2 and B.6 of Form 8-K, the foregoing information, including Exhibit 99.1, shall not be deemed filed for the purposes of Section 18 of the Securities Exchange Act, nor shall such information and Exhibit be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such a filing.

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SIGNATURES

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

	FOREST OIL CORPORATION
	(Registrant)
Dated: August 8, 2003	By:	/s/  JOAN C. SONNEN Joan C. Sonnen Vice President—Controller & Chief Accounting Officer

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INDEX TO EXHIBITS FILED WITH THE CURRENT REPORT ON FORM 8-K

Exhibit	Description
99.1	Forest Oil Corporation press release dated August 6, 2003, entitled "Forest Oil Announces 113% Increase in Net Earnings for the Second Quarter and Reports Operational Results"

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QuickLinks

Item 7. Financial Statements, Pro Forma Financial Information and Exhibits.
Item 9 and Item 12. Regulation FD Disclosure and Results of Operations and Financial Condition.

SIGNATURES

INDEX TO EXHIBITS FILED WITH THE CURRENT REPORT ON FORM 8-K

EX-99.1

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Exhibit 99.1

NEWS	FOR FURTHER INFORMATION
FOREST OIL CORPORATION 1600 BROADWAY, SUITE 2200 DENVER, COLORADO 80202	CONTACT: MICHAEL N. KENNEDY MANAGER OF INVESTOR RELATIONS (303) 812-1739
FOR IMMEDIATE RELEASE

FOREST OIL ANNOUNCES 113% INCREASE IN NET EARNINGS FOR THE SECOND QUARTER AND REPORTS OPERATIONAL RESULTS

DENVER, COLORADO—August 6, 2003—Forest Oil Corporation (NYSE:FST) (Forest) today announced financial and operational results for the second quarter and first six months of 2003 and provided information regarding certain of its exploration and production activities.

SECOND QUARTER 2003 RESULTS

        For the quarter ended June 30, 2003, Forest reported net earnings of $23.4 million or $.49 per basic share, an increase of 113% compared to net earnings of $11.0 million or $.23 per share in the second quarter of 2002. For the six months ended June 30, 2003, Forest reported net earnings of $62.3 million or $1.30 per basic share, an increase of 577% compared to net earnings of $9.2 million or $.20 per share in the corresponding 2002 period.

        Higher earnings for the quarter and six months ended June 30, 2003 compared to the corresponding periods of 2002 were the result of increased operating margins from the combination of higher average oil and gas sales prices and lower oil and gas production expense.

Comparative Financial and Operating Data

        The following table sets forth certain of Forest's financial and operating statistics for the three and six months ended June 30, 2003 and 2002:

		Three Months Ended June 30,			Six Months Ended June 30,
		2003		2002	2003	2002
Daily natural gas sales volumes (MMCF):
	United States		217.8	220.5	220.9	212.1
	Canada		32.4	38.1	32.3	40.6
	Total		250.2	258.6	253.2	252.7
Daily liquids sales volumes (MBBLS):
	United States		22.0	23.5	21.0	20.7
	Canada		2.8	3.0	2.9	3.3
	Total		24.8	26.5	23.9	24.0
Equivalent daily sales volumes (MMCFE):
	United States		349.7	361.4	347.1	336.4
	Canada		49.5	56.0	49.8	60.4
	Total		399.2	417.4	396.9	396.8
Total equivalent sales volumes (BCFE)			36.3	38.0	71.8	71.8
Oil and gas sales revenue (millions)		$	153.6	125.6	321.8	221.4
Average gas sales price ($/MCF)		$	4.39	3.14	4.66	2.91
Average liquids sales price ($/BBL)		$	23.76	21.53	24.90	20.30
Oil and gas production expense (per MCFE)		$	..98	1.06	..98	1.08

Non-GAAP Financial Measures

        In addition to reporting net cash provided by operating activities as defined under U.S. Generally Accepted Accounting Principles (GAAP), Forest also presents discretionary cash flow before interest and taxes, which consists of operating cash flow before working capital changes, interest expense, current income tax expense and amortization of certain deferred items. Management uses this measure to assess the company's ability to generate cash to fund exploration and development activities and to service debt. Management interprets trends in this measure in a similar manner as trends in cash flow and liquidity. Discretionary cash flow before interest and taxes should not be considered as an alternative to net cash provided by operating activities as defined by GAAP. The following is a

reconciliation of net cash provided by operating activities to discretionary cash flow before interest and taxes:

		Three Months Ended June 30,					Six Months Ended June 30,
		2003			2002		2003		2002
		(In Thousands)
Net cash provided by operating activities		$	89,239		80,297		162,847		90,161
(Decrease) increase in accounts receivable			(42,299	)	(18,917	)	22,720		(28,956	)
Increase (decrease) in other current assets			98		(8,941	)	(624	)	(9,013	)
Decrease in accounts payable			31,784		8,312		9,867		47,674
Decrease in accrued interest and other liabilities			16,028		3,723		10,897		1,478
	Cash flow before working capital changes		94,850		64,474		205,707		101,344
Current income tax expense			369		143		426		254
Interest expense			12,491		12,568		25,451		24,713
Amortization of deferred hedge gain			1,107		—		2,202		—
Amortization of deferred debt costs			(562	)	(548	)	(1,121	)	(1,041	)
	Discretionary cash flow before interest and taxes	$	108,255		76,637		232,665		125,270

Second Quarter and Six Months 2003 Financial and Operational Results

        For the quarter and six months ended June 30, 2003, oil and gas sales revenue increased 22% and 45%, respectively, compared to the corresponding periods in 2002. The increases were the result of higher product prices. Average gas sales prices increased 40% and 60% in the second quarter and first six months of 2003, respectively, compared to 2002. Average liquids sales prices increased 10% and 23%, respectively, in the second quarter and first six months of 2003 compared to the corresponding periods in 2002.

        For the second quarter of 2003, Forest reported sales volumes of 36.3 BCFE for an average daily sales volume of approximately 399 MMCFE per day, a 4% decrease compared to reported sales volumes of 38.0 BCFE and an average daily sales volume of approximately 417 MMCFE per day for the same period of 2002. For the first six months of both 2003 and 2002, Forest reported sales volumes of 71.8 BCFE for an average daily sales volume of approximately 397 MMCFE per day. In the United States, Forest's average daily oil and gas sales volumes increased 1% and 4%, respectively, or a total increase in equivalent gas production of approximately 3% in the first six months of 2003 compared to the corresponding prior year period. The increase was attributable primarily to new gas production in the Gulf of Mexico and new oil production in Alaska. In Canada, Forest's average daily sales volumes decreased 18% in the first six months of 2003 due primarily to higher royalty volumes in the current higher price environment and to the effects of property divestitures made in 2002.

        Oil and gas production expense decreased 12% to $35.5 million for the second quarter of 2003 and decreased 9% to $70.7 million for the six months ended June 30, 2003, compared to $40.4 million and $77.6 million, respectively, for the comparable periods in 2002. On a per-unit basis, production expense decreased 9% to $.98 per MCFE in the first six months of 2003 compared to $1.08 per MCFE in the first six months of 2002. The decreases were due primarily to lower lease operating and workover expense in the Gulf of Mexico and Alaska and lower transportation expense in all business units. The decreases were offset partially by higher production taxes in the Western Business Unit as a result of higher product prices and by additional lease operating costs in Alaska in conjunction with the new production at the Redoubt Shoal Field.

        Total overhead costs (capitalized and expensed general and administrative costs) decreased 7% to $16.0 million in the second quarter of 2003 and 5% to $30.0 million in the first six months of 2003, respectively, compared to $17.2 million and $31.6 million in the comparable periods of 2002. The decreases resulted primarily from cost reduction measures in the area of professional service costs and from higher credits for exploration and development activities, offset partially by severance costs and

costs incurred to terminate a Canadian defined benefit pension plan. The expensed portion of overhead costs increased to approximately 64% of total overhead in the 2003 periods from approximately 58% in the 2002 periods, primarily as a function of the higher exploration and development credits in 2003. Accordingly, general and administrative expense increased to $10.2 million and $19.1 million for the quarter and six months ended June 30, 2003, respectively, compared to $10.1 million and $18.2 million for the same periods in 2002.

        Depreciation and depletion expense was $51.6 million and $100.2 million for the quarter and six months ended June 30, 2003, respectively, compared to $47.6 million and $87.8 million for the comparable periods of 2002. On a per-unit basis, the depletion rates were $1.39 and $1.36 per MCFE for the quarter and first six months ended June 30, 2003, respectively, compared to $1.23 and $1.20 per MCFE in the corresponding prior year periods. The higher rates in 2003 were due primarily to higher finding costs in the last six months of 2002 and first quarter of 2003.

        Accretion expense of $3.1 million and $6.3 million in the second quarter and first six months of 2003 was related to the accretion of Forest's asset retirement obligation pursuant to Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), adopted January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Using a cumulative effect approach, in the first quarter of 2003 Forest recorded an increase to net properties and equipment of $102.3 million (net of tax), an asset retirement obligation liability of $96.4 million net of tax and an after tax credit of $5.9 million for the cumulative effect of the change in accounting principle.

        Other expense of $2.6 million in the second quarter of 2003 consisted primarily of Forest's share of the net loss recorded by the Cook Inlet Pipeline Company, an equity method investee in which Forest owns a 40% interest. Other expense of $6.6 million in the first six months of 2003 included a loss on early extinguishment of debt of approximately $4.0 million related to Forest's redemption in January 2003 of its remaining 10¹/2% Notes at 105.25% of par value.

        Interest expense was $12.5 million and $25.5 million for the quarter and six months ended June 30, 2003, respectively, compared to $12.6 million and $24.7 million for the comparable periods of 2002. In the second quarter of 2003, the effects of higher average debt balances were more than offset by lower average interest rates on variable and fixed rate debt. The increase in interest expense in the first six months of 2003 was due to higher average debt balances, partially offset by lower average interest rates.

OPERATIONAL PROJECT UPDATE

Alaska Business Unit

Redoubt Shoal (100% Working Interest)

        The RU #4A was drilled to a depth of 18,082 feet and is currently testing. The rig will be moved to the #7 location after completion of testing.

        Production results from the recently completed RU #6 well and drilling results from the RU #4A well which is currently being tested, are below our original expectations and will result in a change to our existing geologic model of the Redoubt Shoal field. Forest will undertake an integrated study on the field and develop geologic and reservoir models that appropriately reflect the apparent reservoir complexity and heterogeneity.

        Since we are early in the life of this field, the results of this study, considered together with continued production performance, results of testing and completion from the RU #4A well, and drilling results from the RU #7 well should help determine by year-end whether field performance can be improved and whether current Redoubt reserve estimates should be revised.

Cosmopolitan Prospect (12.5% Working Interest)

        The Hansen #1 well was sidetracked to a upstructure position at a total measured depth of 20,789 feet and completed with a horizontal section through the Starichkof and Hemlock intervals. After a short test, the rig was released and the well is being prepared for an extended production test.

Canada Business Unit

Foothills—Narraway Area (55 - 100% Working Interest)

        Following spring break up the Narraway 11-23 was completed and tested. It was placed on production in July at a rate of 14 MMcf/d in the Cadomin and Nikinassin zones. Drilling is progressing on two additional wells (2-27 and 16-7), which are expected to be on production late in the third quarter and early in the fourth quarter, respectively. The 14-15 well was recompleted in the Cadotte zone following receipt of commingling approval. The well was placed on production at 2.3 MMcf/d in early July. Gross production from Forest's operated wells in Narraway now exceeds 28 MMcf/d, the highest level Forest has achieved to-date in this field.

Northwest Territories—Ft. Liard Area (20 - 75% Working Interest)

        The operator is currently testing the Nahanni formation in the P-16 well that was drilled earlier this year. Forest has a carried interest (6% ORRI BPO, 20% APO WI) in the well.

        The Forest-operated 2K-02 Betamax well (75% WI), which spudded in April, is currently drilling at approximately 14,900 feet. The well is expected to reach total depth in the third quarter.

        The Liard P-66A sidetrack (50% WI) reached total depth in June and is currently producing at a restricted rate of 4-5 MMcf/d.

Gulf Business Unit

Eugene Island 273 (75% Working Interest)

        The D-1 well was drilled to a measured depth of 5,671 feet and logged 112 feet of pay in 13 sands. Additional development wells, including horizontal penetrations, and a new platform are planned for later this year.

High Island 116 (100% Working Interest)

        Several recompletions that were in progress in the late second quarter were placed on line in the third quarter. The B-2 well was completed at 15.8 MMcf/d and the B-1 was completed at 15 MMcf/d.

McAllen Ranch Field, South Texas (100% Working Interest)

        The #41 well was drilled to a depth of 13,230 feet and was completed in June at a rate of 6.8 MMcfe/d. There are three additional wells planned in 2003. Our working interest in the field was also increased during the second quarter from 50 to 100 percent as a result of purchasing our partner's interests and additional acreage adjacent to the field. The net production from the field has increased from approximately 4.0 MMcfe/d to 12.0 MMcfe/d during the course of the second quarter.

Katy Field, South Texas (53% Working Interest)

        The latest well in the Middle Wilcox exploitation program, the W-57, was tested at 1.4 MMcfe/d following fractures stimulation. This makes eight out of eight successful recompletions since the start of the program. There are currently three additional recompletions in progress. The 3-D survey is in progress with initial processing expected before year end.

South Bonus Field, South Texas

        In May 2003, Forest successfully acquired the assets of a relatively small operator in this area. The purchase consisted of 4 active wells making 2.4 MMcf/d net and, most importantly, a range of 80 to

100 percent working interest in 56,000 gross acres along with a 3-D seismic shoot. Drilling is expected to begin in August.

Western Business Unit

Anadarko Basin, Western Oklahoma (7 - 24% Working Interest)

        Forest is participating in the completion of one well and is in the process of drilling a second well in the Cement Field. Forest is also participating in five wells that are at various stages of drilling or completing in Elk City Field.

Apollo Field, West Texas (62% Working Interest)

        The University Block 21 #232 was completed, flowing 2.1 MMcf/d and 203 Bbls/d from the Wolfcamp formation. The University Block 21 #265 reached total depth at 13,400 feet and is currently being completed. The University Block 21 #264 commenced drilling.

Vermejo Field, West Texas (100% Working Interest)

        The Steelhead #1 was deepened to a depth of approximately 20,100 feet and tested 5.0 MMcfe/d from the Ellenburger formation. The CO₂ sweetening unit installation will be completed in August allowing first sales.

Permian Acquisition, West Texas (99 - 100% Working Interest)

        Forest closed in early August on the acquisition of four producing oil fields. These fields are currently producing 1,600 Bbls/d. The purchase price was approximately $33 million.

Wild Rose Area, Wyoming (50 - 100% Working Interest)

        Two Forest-operated wells were drilled in the second quarter of 2003. There are four to eight additional development wells planned in the Wild Rose and West Wild Rose areas. The West Wild Rose State #3-16 discovery well is expected to be connected to the pipeline in August.

International Business Unit

Ibhubesi, South Africa (53% Working Interest)

        PetroSA has completed the required funding of $30 million to earn a 24% interest in the Ibhubesi Gas Project. A four to six well drilling program is expected to commence in August using a semi-submersible rig. Forest will have its interest fully carried in this drilling program.

Gabon, West Africa (44.5% Working Interest)

        The Pembi #1 drilled to a total depth of 1,500 and was a dry hole. Forest had its interest fully carried in this well. The operator is evaluating options on the remaining acreage.

2003 GUIDANCE

        Forest has determined that it will not provide financial and operational guidance after 2003. Throughout 2003, we will continue to update the annual guidance as set forth in our press release dated February 12, 2003. No quarterly guidance will be provided for the remainder of 2003.

Overall Summary of Proposed Activity

        Given these general limitations and those discussed below, the assumptions underlying Forest's forecast for 2003 are set forth below:

        Daily Production.    We have assumed that our daily production will be between 400 and 420 MMCFE per day for the full year of 2003.

        Liquids Production.    We have assumed that our production of oil and natural gas liquids will be between 23,000 and 25,000 barrels per day.

        Gas Production.    We have assumed that our natural gas production will be between 255 and 275 MMCF per day.

        Liquids Price Differentials.    We have assumed that our average differential between NYMEX oil prices and realized liquids prices will be between $2.50 and $3.50 per barrel. This does not include hedging activity.

        Gas Price Differentials.    We have assumed that our average differential between NYMEX gas prices and realized gas prices will be between $.30 and $.50 per MCF. This does not include hedging activity.

        Hedging.    Forest has swaps in place for the remainder of 2003 covering the aggregate average daily volumes and weighted average prices shown below.

Natural gas swaps:
Contract volumes (BBTU/d)		80.1
Weighted average price (per MMBTU)	$	4.49
Natural gas collars:
Contract volumes (BBTU/d)		26.6
Weighted average ceiling price (per MMBTU)	$	4.61
Weighted average floor price (per MMBTU)	$	3.40
Oil swaps:
Contract volumes (MBbls/d)		7.3
Weighted average price (per Bbl)	$	23.28
Oil collars:
Contract volumes (MBbls/d)		3.0
Weighted average ceiling price (per Bbl)	$	25.42
Weighted average floor price (per Bbl)	$	22.00

        Production Expense.    Our oil and gas production expense (which includes production taxes and product transportation) varies in response to several factors. Among the most significant of these factors are additions to or deletions from our property base, changes in production taxes, general changes in the prices of services and materials that are used in the operation of our properties and the amount of repair and workover activity required. We have assumed that our production expense will be between $145 million and $155 million.

        Depreciation, Depletion and Amortization (DD&A).    We have assumed that the DD&A rate will be between $1.30 and $1.50 per MCFE.

        Accretion expense.    We have assumed that accretion of the asset retirement obligation will be between $10 million and $14 million.

        Capital Expenditures.    We have assumed that capital expenditures will be between $350 million and $400 million. Some of the factors impacting the level of capital expenditures in 2003 include absolute crude oil and natural gas prices, the volatility in these prices and the cost and availability of oil field services.

        General and Administrative Expense (G&A).    We have assumed that our G&A expense will be between $36 million and $40 million.

        Interest Expense.    We have assumed that our interest expense will be between $46 million and $50 million, depending on the timing of cash flows and capital expenditures. All floating rate debt has been considered in the assumed interest expense. We have assumed that the one-month LIBOR rate will average 2% in 2003.

        Income Taxes.    We have assumed that our effective income tax rate will be 42% (inclusive of applicable federal and state taxes) and our current tax will be 0 to 1% of the total tax expense.

        Shares Outstanding.    We have assumed that diluted shares will be between 48 million and 50 million shares during 2003.

FORWARD-LOOKING STATEMENTS

        This news release 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 that the Company assumes, plans, expects, believes, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements provided in this press release are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Forest cautions that its future natural gas and liquids production, revenues and expenses and other forward-looking statements are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of oil and gas. These risks include, but are not limited to, price volatility, inflation or 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 production or reserves, and other risks as described in Forest's 2002 Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Also, the financial results of Forest's foreign operations are subject to currency exchange rate risks. Any of these factors could cause Forest's actual results and plans to differ materially from those in the forward-looking statements.

TELECONFERENCE CALL

        Forest Oil Corporation management will hold a teleconference call on Thursday, August 7, 2003, at 11:00 a.m. EST (9:00 MST) to review second quarter 2003 results. If you would like to participate please call 800.884.5695 (for U.S./Canada) or 617.786.2960 (for International) and request the Forest Oil teleconference or participant passcode #42019266.

        A replay will be available from Thursday, August 7 through Friday, August 15, 2003. You may access the replay by dialing toll free 888.286.8010 (for U.S./Canada) or 617.801.6888 (for International), reservation #37160346. Please note that the reservation number is not needed to access the teleconference, only the replay.

* * * * *

        Forest Oil Corporation is engaged in the acquisition, exploration, development, production and marketing of natural gas and crude oil in North America and selected international locations. Forest's principal reserves and producing properties are located in the United States in Alaska, Louisiana,

Oklahoma, Texas, Utah, Wyoming and the Gulf of Mexico, and in Canada in Alberta and the Northwest Territories. Forest's common stock trades on the New York Stock Exchange under the symbol FST. For more information about Forest, please visit its website at www.ForestOil.com.

August 6, 2003

###

FOREST OIL CORPORATION
Condensed Consolidated Balance Sheets
(Unaudited)

			June 30, 2003			December 31, 2002
			(In Thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	10,221		13,166
	Accounts receivable			140,503		111,760
	Derivative instruments			2,524		3,241
	Current deferred tax asset			19,424		10,310
	Other current assets			21,873		21,994
		Total current assets		194,545		160,471
Net property and equipment				1,963,529		1,687,885	:
Deferred income taxes				1,303		41,022
Goodwill and other intangible assets, net				13,870		12,525
Other assets				20,673		22,778
			$	2,193,920		1,924,681
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	150,273		153,413
	Accrued interest			3,657		6,857
	Derivative instruments			41,124		29,120
	Asset retirement obligation			14,357		—
	Other current liabilities			3,464		2,285
		Total current liabilities		212,875		191,675
Long-term debt				745,563		767,219
Asset retirement obligation				145,962		—
Other liabilities				25,489		28,199
Deferred income taxes				25,271		16,377
Shareholders' equity:
	Common stock			5,029		4,913
	Capital surplus			1,183,657		1,159,269
	Accumulated deficit			(82,563	)	(144,548	)
	Accumulated other comprehensive loss			(11,493	)	(41,887	)
	Treasury stock, at cost			(55,870	)	(56,536	)
		Total shareholders' equity		1,038,760		921,211
			$	2,193,920		1,924,681

FOREST OIL CORPORATION
Condensed Consolidated Statements of Operations
(Unaudited)

				Three Months Ended June 30,				Six Months Ended June 30,
				2003		2002		2003		2002
				(In Thousands Except Per Share Amounts)
Revenue:
	Oil and gas sales:
		Natural gas		$	99,870	73,797		213,828		133,229
		Oil, condensate and natural gas liquids			53,705	51,849		107,947		88,213
			Total oil and gas sales		153,575	125,646		321,775		221,442
		Marketing and processing, net			1,275	1,241		1,818		1,878
			Total revenue		154,850	126,887		323,593		223,320
Operating expenses:
	Oil and gas production				35,512	40,375		70,712		77,586
	General and administrative				10,173	10,062		19,065		18,219
	Depreciation and depletion				51,576	47,588		100,206		87,774
	Accretion of asset retirement obligation				3,147	—		6,267		—
	Impairment of oil and gas properties				135	—		135		—
			Total operating expenses		100,543	98,025		196,385		183,579
Earnings from operations					54,307	28,862		127,208		39,741
Other income and expense:
	Other expense, net				2,649	1,743		6,570		2,717
	Interest expense				12,491	12,568		25,451		24,713
	Translation gain on subordinated debt				—	(2,970	)	—		(2,821	)
	Realized loss (gain) on derivative instruments, net				5	(162	)	(38	)	(246	)
	Unrealized loss on derivative instruments, net				122	416		127		616
			Total other income and expense		15,267	11,595		32,110		24,979
Earnings before income taxes and cumulative effect of change in accounting principle					39,040	17,267		95,098		14,762
Income tax expense:
	Current				369	143		426		254
	Deferred				15,259	6,166		38,243		5,334
					15,628	6,309		38,669		5,588
Earnings before cumulative effect of change in accounting principle					23,412	10,958		56,429		9,174
Cumulative effect of change in accounting principle for recording asset retirement obligation, net of taxes					—	—		5,854		—
Net earnings				$	23,412	10,958		62,283		9,174
Weighted average number of common shares outstanding:
	Basic				48,188	46,925		48,024		46,880
	Diluted				49,068	48,485		48,901		48,293
Basic earnings per common share:
	Earnings before cumulative effect of change in accounting principle			$	.49	.23		1.18		.20
	Cumulative effect of change in accounting principle				—	—		.12		—
	Basic earnings per common share			$	.49	.23		1.30		.20
Diluted earnings per common share:
	Earnings before cumulative effect of change in accounting principle			$	.48	.23		1.15		.19
	Cumulative effect of change in accounting principle				—	—		.12		—
	Diluted earnings per common share			$	.48	.23		1.27		.19

FOREST OIL CORPORATION
Condensed Consolidated Statements of Cash Flows
(Unaudited)

				Six Months Ended June 30,
				2003			2002
				(In Thousands)
Cash flows from operating activities:
	Net earnings before cumulative effect of change in accounting principle			$	56,429		9,174
	Adjustments to reconcile earnings to net cash provided by operating activities:
		Depreciation and depletion			100,206		87,774
		Accretion of asset retirement obligation			6,267		—
		Impairment of oil and gas properties			135		—
		Amortization of deferred hedge gain			(2,202	)	—
		Amortization of deferred debt costs			1,121		1,041
		Translation gain on subordinated debt			—		(2,821	)
		Unrealized loss on derivative instruments, net			127		616
		Deferred income tax expense			38,243		5,334
		Loss on extinguishment of debt			3,975		1,998
		Loss in equity method investee			1,580		—
		Other, net			(174	)	(1,772	)
		(Increase) decrease in accounts receivable			(22,720	)	28,956
		Decrease in other current assets			624		9,013
		Decrease in accounts payable			(9,867	)	(47,674	)
		Decrease in accrued interest and other liabilities			(10,897	)	(1,478	)
			Net cash provided by operating activities		162,847		90,161
Cash flows from investing activities:
	Capital expenditures for property and equipment:
		Exploration, development and acquisition costs			(166,102	)	(179,194	)
		Other fixed assets			(1,202	)	(2,114	)
	Proceeds from sales of assets				65		1,632
	Increase in other assets, net				(1,112	)	(2,296	)
			Net cash used by investing activities		(168,351	)	(181,972	)
Cash flows from financing activities:
	Proceeds from bank borrowings				321,000		177,889
	Repayments of bank borrowings				(275,000	)	(196,878	)
	Issuance of 73/4% senior notes, net of issuance costs				—		146,846
	Repurchases of 83/4% senior subordinated notes				—		(5,435	)
	Repurchases of 101/2% senior subordinated notes				(69,441	)	(21,283	)
	Proceeds of common stock offering, net of offering costs				20,968		—
	Proceeds from the exercise of options and warrants				4,152		3,573
	Purchase of treasury stock				—		(560	)
	Increase (decrease) in other liabilities, net				126		(497	)
			Net cash provided by financing activities		1,805		103,655
Effect of exchange rate changes on cash					754		(4	)
Net (decrease) increase in cash and cash equivalents					(2,945	)	11,840
Cash and cash equivalents at beginning of period					13,166		8,387
Cash and cash equivalents at end of period				$	10,221		20,227

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Exhibit 99.1