Exhibit 99.1

NEWS	FOR FURTHER INFORMATION
FOREST OIL CORPORATION	CONTACT: PATRICK J. REDMOND
707 17th STREET, SUITE 3600	DIRECTOR - INVESTOR RELATIONS
DENVER, COLORADO 80202	303.812.1441

FOR IMMEDIATE RELEASE

FOREST OIL ANNOUNCES SECOND QUARTER RESULTS INCLUDING A SUBSTANTIAL
INCREASE IN SALES VOLUMES

•Forest’s second quarter sales volumes of 325 MMcfe/d increased 17% year over year and 14% sequentially (Remainco)

•“Big Three” growth assets (Buffalo Wallow, Wild River and Cotton Valley) all set record production levels

•Continued success in the Greater Vermejo/Haley area

•Net earnings of $57 million or $.92 per basic share increased 105% compared to 2005 Remainco

•Discretionary cash flow of $118 million increased 28% compared to 2005 Remainco

•Forest assumed operatorship of the Katy Field; announces field study eyeing significant 2007 workover and drilling program

•Forest entered into a joint exploration agreement in the Barnett Shale, increasing total acreage to approximately 20,000 gross acres

DENVER, COLORADO — August 7, 2006 - Forest Oil Corporation (NYSE:FST) (Forest or the Company) today announced financial and operational results for the second quarter of 2006.  The Company reported the following highlights:

•Forest’s net sales volumes increased to 325 MMcfe/d, an increase of 17%, including an 8 MMcfe/d positive effect from reduced Alaska oil inventory, compared to 2005 Remainco

•Discretionary cash flow increased to $118 million, an increase of 28% compared to 2005 Remainco

•Adjusted EBITDA increased to $138 million, an increase of 30% compared to 2005 Remainco

H. Craig Clark, President and CEO, stated, “This quarter represents the first time that Forest is able to report results solely from our repositioned onshore North American asset base and the results speak for themselves; significant production growth and lower than expected production costs.  In addition to the positive operating results, we have had two significant recent developments in the assumption of operatorship in the Katy Field and the development of an exploration joint venture in the Barnett Shale.  These two events will greatly increase our inventory of high quality development locations and could be impactful for 2007.  We have now begun to develop plays beyond our “Big Three” assets.”

DISCUSSION OF SECOND QUARTER PRO FORMA RESULTS

The following discussion compares Forest’s second quarter results in 2006 to 2005 pro forma for the spin-off (“Spin-off”) of its Gulf of Mexico operations and subsequent merger of those operations with a subsidiary of Mariner Energy, Inc. on March 2, 2006 and includes non-GAAP measures.  See “Non-GAAP Financial Measures” below for further information.  We refer to the portion of Forest not included in the Spin-off as “Remainco” and the Spin-off properties as “Spinco”.

For the quarter ended June 30, 2006, Forest had net earnings of $57.0 million or $.92 per basic share.  This amount is an increase of 105% compared to Remainco’s pro forma net earnings of $27.9 million or $.45 per basic share in the corresponding period in 2005.  The net earnings in the second quarter of 2006 were affected by unrealized gains on derivative instruments of $14.4 million ($8.8 million net of tax), a reduction in the deferred tax liability of $16.2 million ($16.2 million net of tax) to reflect lower statutory rates in Alberta and a change in the Texas state tax regulations, and a $2.1 million ($1.3 million net of tax) impairment related to a dry hole drilled in Gabon.  Without the effect of these items, Forest’s net earnings would have been $33.3 million or $.53 per basic share.  This amount compares to Remainco’s pro forma net earnings of $25.5 million or $.42 per basic share in the corresponding 2005 period computed on a comparable basis excluding unrealized gains on derivative instruments of $3.8 million ($2.4 million net of tax).

For the three months ended June 30, 2006, Forest’s oil and gas sales volumes increased to 325 MMcfe/d or 17% over Remainco’s 279 MMcfe/d in the corresponding period in 2005.  Second quarter sales volumes reflect additional tanker liftings in Alaska (8 MMcfe/d) following an inventory build in the first quarter.  The following table sets forth Forest’s sales data for the three and six months ended June 30, 2006 and 2005 displayed for both Remainco and Spinco:

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	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
DAILY VOLUMES
Daily natural gas sales volumes (MMcf):
United States	126.5	96.7	114.9	90.7
Canada	65.5	48.9	64.6	48.9
Total Remainco	192.0	145.6	179.5	139.6
Spinco	—	157.4	35.2	165.7
Total	192.0	303.0	214.7	305.3
Daily oil and condensate sales volumes (MBbls):
United States	15.1	14.8	13.9	15.1
Canada	2.0	2.4	2.1	2.4
Total Remainco	17.1	17.2	16.0	17.5
Spinco	—	7.0	1.1	7.3
Total	17.1	24.2	17.1	24.8
Daily natural gas liquids sales volumes (MBbls):
United States	3.8	3.9	3.8	3.0
Canada	1.2	1.1	1.1	1.2
Total Remainco	5.0	5.0	4.9	4.2
Spinco	—	2.3	0.5	2.6
Total	5.0	7.3	5.4	6.8
Equivalent daily sales volumes (MMcfe):
United States	240.4	208.9	221.2	199.2
Canada	84.5	69.	83.7	70.5
Total Remainco	324.9	278.7	304.9	269.7
Spinco	—	213.0	44.5	225.3
Total	324.9	491.7	349.4	495.0

Forest’s oil and gas sales revenue increased 35% during the second quarter of 2006 to $210.2 million compared to Remainco’s $155.9 million in 2005.  The increase was a result of increased gas sales volumes and higher oil prices.  The following table reflects sales price information for the three months ended June 30, 2006 and 2005 displayed for both Remainco and Total Company:

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	Remainco					Total Company
	Three months ended June 30,
	2006			2005		2006		2005
NATURAL GAS (per Mcf except NYMEX):
NYMEX (per MMbtu)	$	6.79		6.73		6.79		6.73
Sales price	$	5.26		5.82		5.26		6.39
Effects of energy derivatives (1)	0.16			(0.21	)	0.16		(0.58	)
Average sales price	$	5.42		5.61		5.42		5.81
Average natural gas differential	$	1.53		0.91		1.53		0.34
LIQUIDS (per Bbl):
OIL AND CONDENSATE:
NYMEX	$	70.70		53.13		70.70		53.13
Sales price	$	65.93		48.61		65.93		49.37
Effects of energy derivatives (1)	(2.81		)	(4.42	)	(2.81	)	(8.01	)
Average sales price	$	63.12		44.19		63.12		41.36
NATURAL GAS LIQUIDS (per Bbl):
Sales price	$	37.29		26.97		37.29		27.62
LIQUIDS SUMMARY (per Bbl):
Sales price	$	59.45		43.74		59.45		44.32
Effect of energy derivatives (1)	(2.17		)	(3.43	)	(2.17	)	(6.15	)
Average sales price	$	57.28		40.31		57.28		38.17
Average liquids differential	$	11.25		9.39		11.25		8.81

(1) Represents amortization of hedging gains and losses in the three months ended June 30, 2006 as the result of electing to discontinue hedge accounting in March 2006. Realized and unrealized gains and losses on derivative instruments are not reflected in these amounts.

Forest’s lease operating expense (LOE) increased 34% to $35.5 million for the quarter ended June 30, 2006 from Remainco’s $26.6 million for the corresponding period in 2005.  On a per-unit basis, LOE increased 14% to $1.20 per Mcfe in 2006 from Remainco’s $1.05 per Mcfe in the same period in 2005.  The increase is primarily attributable to higher fuel and electrical costs and Canadian exchange rates.

Forest’s production and property taxes increased 12% to $11.0 million during the second quarter of 2006 compared to Remainco’s $9.9 million during the second quarter of 2005.  The increase was attributable to higher oil prices in 2006 compared to the second quarter of 2005.  As a percentage of oil and natural gas revenue, excluding hedging losses, production and property taxes for the three months ended June 30, 2006 for Forest were 5.2% and in the comparable period of 2005 were 6.0% for Remainco.  The decreased rate was a result of realizing severance tax relief in Texas on “tight sands” gas wells.  The components of oil and gas production expense attributable to Remainco and Total Company were as follows for the three months ended June 30, 2006 and 2005:

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	Three Months Ended June 30,
Remainco	2006			Per Mcfe	2005	Per Mcfe
	(in thousands, except per unit amounts)
Direct operating expense and overhead	$		32,840	1.11	23,850	0.94
Workovers	2,689			0.09	2,731	0.11
Lease operating expense	35,529			1.20	26,581	1.05
Production and property taxes	10,997			0.37	9,857	0.39
Transportation costs	5,642			0.19	3,564	0.14
Total	$	52,168		1.76	40,002	1.58
	Three Months Ended June 30,
Total Company	2006			Per Mcfe	2005	Per Mcfe
	(in thousands, except per unit amounts)
Direct operating expense and overhead	$	32,840		1.11	38,336	0.85
Workovers	2,689			0.09	7,447	0.17
Lease operating expense	35,529			1.20	45,783	1.02
Production and property taxes	10,997			0.37	10,547	0.24
Transportation costs	5,642			0.19	4,583	0.10
Total	$	52,168		1.76	60,913	1.36

Forest’s general and administrative expense increased 4% to $11.1 million for the quarter ended June 30, 2006 compared to $10.7 million for Remainco for the corresponding period in 2005.  The increase resulted primarily from non-cash stock-based compensation expense in the second quarter of 2006 of $2.5 million compared to $.2 million in 2005.  The increase in stock-based compensation expense was offset by decreased salaries and wages as a result of fewer employees following the Spin-off.

Depreciation and depletion (“DD&A”) expense increased 27% to $63.3 million for the quarter ended June 30, 2006 compared to $49.8 million for Remainco for the corresponding period in 2005, primarily due to increased production.  On a per-unit basis, the depreciation and depletion rate was $2.14 per Mcfe for the quarter ended June 30, 2006, an increase of 9% compared to $1.96 per Mcfe for Remainco in the corresponding period in 2005.  The increase reflects acquisition costs at higher than historical DD&A rates.

CAPITAL ACTIVITIES

In the second quarter of 2006, Forest invested $135 million in exploration and development activities.  The following table summarizes capital expenditures incurred in the second quarter of 2006 for exploration and development, and acquisition activities (in millions):

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	U.S.		Canada	International	Total
Exploration and
development	$	105	25	5	135
Acquisitions	4		—	—	4
Total	$	109	25	5	139

DERIVATIVES

Forest currently has derivatives in place for the remainder of 2006 and 2007 covering the aggregate average daily volumes and weighted average prices shown below.  The following is a complete detail of all derivatives Forest has in place in 2006 and 2007 as of August 7, 2006:

	Remainder of 2006 (3)					2007 (3)
Natural gas swaps:
Contract volumes (Bbtu/d)	10.0				(1)	—
Weighted average price (per MMBtu)	$		5.51			—
Natural gas collars:
Contract volumes (Bbtu/d)	50.0					35.0			(2)
Weighted average ceiling price (per MMBtu)	$		11.88			$		11.70
Weighted average floor price (per MMBtu)	$		7.43			$		8.76
Oil swaps:
Contract volumes (MBbls/d)	7.5				(2)	3.5
Weighted average price (per Bbl)	$		51.18			$	73.16
Oil collars:
Contract volumes (MBbls/d)	5.5				(2)	4.0
Weighted average ceiling price (per Bbl)	$			65.87		$	87.18
Weighted average floor price (per Bbl)	$	46.73				$		65.82

(1)	Represents volumes associated with Forest’s acquisition activities.
(2)	15.0 of the 35.0 Bbtu/d of natural gas collars and 5.0 of the 13.0 MBbls/d of oil swaps and collar volumes are associated with Forest’s acquisition activities.
(3)	Included in the table above are hedges Forest entered into subsequent to Forest’s press release dated May 9, 2006. For the remainder of 2006, Forest entered into oil swaps of 3.5 MBbls/d at $73.58 per Bbl. For 2007, Forest entered into natural gas collars covering 20.0 Bbtu/d with weighted average ceiling and floor prices of $12.34 and $8.13 per MMBtu, respectively, oil swaps of 3.5 MBbls/d at $73.16 per Bbl, and oil collars covering 3.0 MBbls/d with weighted average ceiling and floor prices of $87.90 and $66.08 per Bbl, respectively.

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OPERATIONAL PROJECT UPDATE

Western Business Unit

Buffalo Wallow Area, Texas Panhandle (66-100% WI) — During the second quarter, a fifth drilling rig was moved into the area.  A total of 15 wells were drilled in the quarter at a 100% success rate with net production increased to 37 MMcfe/d.  During the quarter an additional 4,000 acres were leased.  The acquired land could add an additional 100 locations.

Greater Vermejo/Haley Area, West Texas (42-100% WI) — Forest continued to add to its leasehold in the area in the second quarter, increasing to a total of 44,000 gross acres.  One new drilling well was completed at 4.9 MMcfe/d and one re-entry project tested at 2.4 MMcfe/d.  There are two re-entries and one drilling project in progress.  Net production has increased to 25 MMcfe/d.  As a result of past success, it is expected that additional capital expenditures will be allocated to this area.

Central Midland Basin, West Texas (25-100% WI) — A total of 13 wells were drilled in the quarter at a 100% success rate.  Initial production rates ranged from 70 to 160 Bbls/d on the shallow oil program and 700 to 800 Mcfe/d for the shallow gas locations.  In the Tex-Mex field alone, we have increased identified development locations to 160 drillsites.

Southern Business Unit

Katy Field, Waller, Harris and Ft. Bend Counties, Texas (52% WI) — Effective August 1, 2006, Forest took over as operator of the field.  The field has 33,000 gross acres, and Forest has 6 to 10 drilling projects planned for 2006 along with facilities modifications.  The capital activity in this field is expected to increase substantially as 31 development locations have already been identified.  Forest will undertake an extensive field study including all 131 existing wellbores with a goal to propose an extensive recompletion and drilling program in 2007.

East Texas Cotton Valley Area, Rusk, Panola and Harrison Counties, Texas (52% WI) — Forest took over operations on this acquisition on April 1, 2006 and has increased production to 15 MMcfe/d.  Forest drilled 9 wells at a 100% success rate that had an average initial production rate of 1.4 MMcfe/d. A third drilling rig was moved into the area from our Lantern Drilling fleet during the third quarter of 2006.  Forest is also finalizing a new gathering and processing contract which will provide for lower wellhead pressures and increased NGL recovery.  Construction of the new facilities and pipelines are expected to be complete by year end.

South Louisiana (96% WI) — Forest’s activity in the Saturday Island Field increased gross production by 7.2 MMcfe/d, and two gas recompletions at West White Lake Field added 4.8 MMcfe/d.  Additional projects are planned for Saturday Island, West White Lake and Sweet Lake in 2006.

Barnett Shale, Hill, Erath and Hamilton Counties, Texas (48 - 100% WI) — Forest’s gross acreage position has been increased to approximately 20,000 acres.  Forest has signed an exploration joint venture agreement with a third party for its eastern acreage in Hill County which covers approximately 14,000 acres.  Each party will participate with approximately 50% working interest in this joint area. The first horizontal well commenced drilling in the third quarter of 2006.

Canada Business Unit

Wild River Area, Alberta, Canada (25-100% WI) — Activity in Wild River decreased in the second quarter due to normal spring road bans.  Forest drilled three wells at a 100% success rate that

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increased net production to 32 MMcfe/d.  The two rig program has resumed with six wells currently awaiting completion or pipeline connection.

Ansell Area, Alberta, Canada (50% WI) — Forest’s gross acreage position in the field is 23,000 acres.  Two wells were drilled and cased in the second quarter with completion operations currently underway.  Up to five additional tests are planned for the remainder of 2006.

Evi Field, Alberta, Canada (25-100% WI) — Shallow oil drilling activity has commenced following the three successful wells in 2005, which tested 50 to 80 Bbls/d.  Additional capital expenditures have been allocated to this program with 52 development locations identified.  Our gross acreage position is approximately 11,000 acres.

Waterton Area, Alberta Foothills, Canada (12-40% WI) — A portion of Forest’s acreage was unitized into a 14 section unit effective May 1, 2006 and Forest’s interest in the unit is approximately 12%.  Two additional unit wells are planned this year to offset the 10-30 discovery which is currently producing in excess of 12 MMcf/d.

Narraway/Copton/Palliser Areas, Alberta Foothills, Canada (50-100% WI) — The Narraway 13-2 previously was completed at 4.8 MMcfe/d and is awaiting a pipeline connection, as are two Palliser wells, which are currently being completed.  Up to two additional wells are planned for later this year.

2006 GUIDANCE

Prices for Forest’s products are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and worldwide economic and political conditions, consumer product demand, weather and other substantially variable factors. These factors are beyond Forest’s control and are difficult to predict. In addition, prices received by Forest for its oil and gas production may vary considerably due to differences between regional markets, transportation availability and demand for different grades of products. Consequently, Forest’s financial results and resources are highly influenced by this price volatility.

Estimates for Forest’s future production are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products.

The production, transportation and marketing of liquids and gas are complex processes that are subject to disruption due to transportation and processing availability, mechanical failure, human error and meteorological events (including, but not limited to, severe weather, hurricanes and earthquakes). Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production will be as estimated.

The following guidance has been updated from the guidance issued on March 16, 2006 to reflect operations to date as follows:

•Production expense range decreased to $190 million to $210 million

•DD&A rate increased to $2.10 to $2.20 per Mcfe

•Capital expenditures estimated to be at the high end of the previously provided range, or $500 million, and additional increases will be considered for positive results at Greater Vermejo/Haley and Katy

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Given these general limitations and those discussed below, the following is a summary of Forest’s updated guidance for 2006:

Daily Production. We estimate that our daily production will be between 300 to 320 MMcfe/d for the full year of 2006.

Liquids Production. We estimate that our daily production of oil and natural gas liquids will be between 19,000 and 21,000 Bbls/d for the full year 2006.

Gas Production. We estimate that our daily natural gas production will be between 185 and 195 MMcf/d for the full year 2006.

Gas Differentials.  Based on current market prices, we estimate that our third quarter 2006 gas price differential from NYMEX will be between $1.35 and $1.65 per Mcf.

Liquids Differentials.  Based on current market prices, we estimate that our third quarter 2006 liquids price differential from NYMEX will be between $11.00 and $15.00 per Bbl.

Production Expense. Our oil and gas production expense (which includes LOE, ad valorem taxes, production taxes and product gathering and 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 estimate that our 2006 production expense will be between $190 million and $210 million.

General and Administrative Expense (G&A). We estimate that our G&A expense, exclusive of the non-cash charges relating to FAS 123R described in the next paragraph, will be between $35 million and $39 million.

Equity Compensation (FAS 123R) Expense. We estimate that we will incur non-cash charges pursuant to FAS 123R of approximately $14 million in 2006. Approximately $8 million was expensed in the first quarter primarily due to the Mariner transaction, and the remainder will be amortized throughout the year.

Depreciation, Depletion and Amortization (DD&A). We estimate that our DD&A rate will be between $2.10 and $2.20 per Mcfe during 2006.

Capital Expenditures. We estimate that expenditures for exploration and development will be approximately $500 million in 2006; however, due to drilling success at Greater Vermejo/Haley and other areas, Forest is considering an increase in the 2006 capital budget later in the third quarter of 2006. Some of the factors impacting the level of capital expenditures in 2006 include the cost and availability of oil field services and weather conditions.

PRO FORMA

Forest presents pro forma statements of operations for Remainco.  The following unaudited pro forma statements of operations of Forest present the operating results of Remainco for the three months ended June 30, 2006 and 2005 giving pro forma effect to the Spin-off.

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The historical financial information of Forest set forth below has been derived from the historical unaudited consolidated financial statements of Forest and the Quarterly Report that will be filed on Form 10-Q for the quarter ended June 30, 2006.

The unaudited pro forma statements of operations presented do not purport to represent what the results of operations or financial position of Remainco would actually have been had the transaction occurred at the beginning of each period presented, or to project the results of operations or financial position of Forest for any future periods. The adjustments to present the pro forma results of Remainco is based on available information and certain assumptions that management believes are reasonable.  Management believes this information allows for a more comprehensive comparison of Remainco’s results in 2006 and 2005.

FOREST OIL CORPORATION

Pro Forma Statements of Operations (Unaudited)

	For the Three Months Ended June 30, 2006						For the Three Months Ended June 30, 2005
	Remainco			Spinco (1)	Total		Remainco		Spinco		Total
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	210,223		—	210,223		155,866	(a)	113,489		269,355
Marketing, processing, and other	1,630			—	1,630		1,700	(a)	—		1,700
Total revenue	211,853			—	211,853		157,566		113,489		271,055
Operating expenses:
Production expense	52,168			—	52,168		40,002	(a)	20,911		60,913
General and administrative	11,071			—	11,071		10,655	(b)	436		11,091
Depreciation and depletion	63,253			—	63,253		49,757	(c)	47,492		97,249
Accretion of asset retirement obligations	1,301			—	1,301		1,161	(d)	3,161		4,322
Impairment	2,078			—	2,078		—		—		—
Total operating expenses	129,871			—	129,871		101,575		72,000		173,575
Earnings from operations	81,982			—	81,982		55,991		41,489		97,480
Other income and expense:
Interest expense	17,340			—	17,340		14,076	(e)	1,985		16,061
Unrealized gains on derivative instruments, net	(14,378		)	—	(14,378	)	(3,770	)(f)	(540	)	(4,310	)
Realized losses (gains) on derivative instruments, net	13,698			—	13,698		(935	)(g)	85		(850	)
Other (income) expense, net	(110		)	—	(110	)	2,434		75		2,509
Total other income and expense	16,550			—	16,550		11,805		1,605		13,410
Earnings before income taxes	65,432			—	65,432		44,186		39,884		84,070
Income tax expense	8,384			—	8,384		16,314	(h)	15,555		31,869
Net earnings	$	57,048		—	57,048		27,872		24,329		52,201
Weighted average number of common shares outstanding:
Basic	62,195				62,195		61,419				61,419
Diluted	63,489				63,489		62,727				62,727
Basic net earnings per common share	$	0.92			0.92		0.45				0.85
Diluted net earnings per common share	$	0.90			0.90		0.44				0.83

(1)  Forest’s offshore assets were spun-off and merged with Mariner on March 2, 2006; therefore there are no Spinco operations or expenses associated with Forest in the second quarter of 2006.

(a)        To allocate revenue and production expense directly attributable to the oil and gas operations of Remainco and Spinco.

(b)        To allocate salaries and other direct general and administrative expenses attributable to Remainco and Spinco. The Spinco allocation includes only general and administrative costs directly related to Forest’s offshore Gulf of Mexico operations. Accordingly, no reductions were assumed for general corporate overhead costs, such as indirect personnel costs, professional services, cost of public ownership, insurance and accounting which occurred subsequent to the Spin-off.

(c)         To allocate depreciation and depletion to give effect to the reduction in Remainco’s consolidated full cost pool and a reduction in production volumes.

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(d)        To allocate accretion expense attributable to asset retirement obligations associated with assets specifically related to Remainco and Spinco.

(e)        To allocate interest expense to give effect to the repayment of a portion of Forest’s outstanding credit facilities using the approximate $200 million in proceeds received from Spinco at the time of the Spin-off.

(f)        To allocate unrealized gains on derivative instruments that did not qualify for cash flow hedge accounting.

(g)         To allocate realized losses (gains) on derivative instruments that did not qualify for cash flow hedge accounting treatment.

(h)        To allocate income tax expense to Remainco and Spinco based on the Forest’s effective deferred federal and state tax rates.

NON-GAAP FINANCIAL MEASURES

In addition to net income determined in accordance with generally accepted accounting principles (“GAAP”), Forest has provided net earnings adjusted for certain items, a non-GAAP financial measure which facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties.  Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to Forest’s ongoing operations.  A reconciliation between GAAP net earnings and net earnings adjusted for certain items are provided in the paragraphs in which the non-GAAP measure is presented.  Net earnings excluding the effects of certain items should not be considered a substitute for net earnings as reported in accordance with GAAP.

In addition to reporting net earnings as defined under GAAP, Forest also presents adjusted EBITDA, which consists of net earnings plus income tax expense, unrealized gains on derivative instruments, net, interest expense, accretion of asset retirement obligations, impairment, depreciation and depletion, and stock-based compensation.  Forest further presents discretionary cash flow, which consists of adjusted EBITDA minus interest expense, current income tax expense, and other non-cash items.  Management uses adjusted EBITDA and discretionary cash flow as measures of operational performance.  Adjusted EBITDA and discretionary cash flow should not be considered as alternatives to net earnings as reported under GAAP. The following is a reconciliation of net earnings to adjusted EBITDA to discretionary cash flow (in thousands):

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	Remainco					Total Company
	Three Months Ended June 30,
	2006			2005		2006		2005
Net earnings	$	57,048		27,872		57,048		52,201
Income tax expense	8,384			16,314		8,384		31,869
Unrealized gains on derivative instruments, net	(14,378		)	(3,770	)	(14,378	)	(4,310	)
Interest expense	17,340			14,076		17,340		16,061
Accretion of asset retirement obligations	1,301			1,161		1,301		4,322
Impairment	2,078			—		2,078		—
Depreciation and depletion	63,253			49,757		63,253		97,249
Stock-based compensation	2,498			154		2,498		154
Adjusted EBITDA	137,524			105,564		137,524		197,546
Interest expense	(17,340		)	(14,076	)	(17,340	)	(16,061	)
Current income tax expense	(1,819		)	(617	)	(1,819	)	(617	)
Other non-cash items	(841		)	758		(841	)	758
Discretionary cash flow	$	117,524		91,629		117,524		181,626

Forest further presents discretionary cash flow on an historical and pro forma basis, which consists of net cash provided by operating activities excluding changes in accounts receivable, other current assets, accounts payable, and accrued interest and other current liabilities.  Forest further presents adjusted EBITDA, which consists of discretionary cash flow excluding interest expense, current income taxes, and other non-cash items.  Management uses these measures to assess the Company’s ability to generate cash to fund exploration and development activities.  Management interprets trends in these measures in a similar manner as it interprets trends in cash flow and liquidity.  Discretionary cash flow and adjusted EBITDA should not be considered as an alternative to net cash provided by operating activities presented in accordance with GAAP (in thousands):

	Total Company
	Three Months Ended June 30,
	2006			2005
Net cash provided by operating activities	$	82,617		189,340
Changes in operating assets and liabilities:
Accounts receivable	(50		)	(26,988	)
Other current assets	(1,519		)	(2,923	)
Accounts payable	12,733			6,210
Accrued interest and other current liabilities	23,743			15,987
Discretionary cash flow	117,524			181,626
Interest expense	17,340			16,061
Current income taxes	1,819			617
Other non-cash items	841			(758	)
Adjusted EBITDA	$	137,524		197,546

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In addition to total debt, Forest also presents net debt, which consists of principal amount of long-term debt less cash and cash equivalents on hand at the end of the period.  Management uses this measure to assess Forest’s indebtedness, based on actual principal amounts owed and cash on hand which has not been applied to reduce amounts drawn on the credit facility.  The following table sets forth the components of net debt as of June 30, 2006 and December 31, 2005 (in millions):

	June 30, 2006			December 31, 2005
	Principal		Book (1)	Principal	Book (1)
Credit facilities	$	359	359	154	154
8% Senior notes due 2008	265		269	265	270
8% Senior notes due 2011	285		297	285	298
7 3/4% Senior notes due 2014	150		162	150	163
Total long-term debt	1,059		1,087	854	885
Cash and cash equivalents	5		5	7	7
Net debt	$	1,054	1,082	847	878

(1) Book amounts include the principal amount of long-term debt adjusted for unamortized gains on interest rate swaps of $23.0 million and $25.5 million at June 30, 2006 and December 31, 2005, respectively, and unamortized net premiums on issuance of $5.0 million and $5.5 million at June 30, 2006 and December 31, 2005, respectively.

TELECONFERENCE CALL

Forest Oil Corporation management will hold a teleconference call on Tuesday, August 8, 2006, at 12:00 pm MT to discuss the items described in this press release.  If you would like to participate please call 800.399.6298 (for U.S./Canada) and 706.634.0924 (for International) and request the Forest Oil teleconference (ID # 3550617).

A replay will be available from Tuesday, August 8, 2006 through August 15, 2006.  You may access the replay by dialing toll free 800.642.1687 (for U.S./Canada) and 706.645.9291 (for International), conference ID # 3550617.

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 Forest 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 in the cost of 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 2005 Annual Report on Form 10-K as filed with the Securities and Exchange

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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.

Forest Oil Corporation is engaged in the acquisition, exploration, development, and production of natural gas and liquids in North America and selected international locations. Forest’s principal reserves and producing properties are located in the United States in Alaska, Louisiana, New Mexico, Oklahoma, Texas, Utah, Wyoming, and in Canada. 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 7, 2006

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FOREST OIL CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)

	June 30, 2006		December 31, 2005
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	5,456	7,231
Accounts receivable	139,673		178,124
Derivative instruments	10,870		941
Deferred tax assets	16,816		77,346
Other current assets	35,054		52,283
Total current assets	207,869		315,925
Net property and equipment	2,590,977		3,200,018
Derivative instruments	3,747		—
Goodwill	87,725		87,072
Other assets	35,583		42,531
	$	2,925,901	3,645,546
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	209,266	312,076
Accrued interest	4,752		4,260
Derivative instruments	49,203		151,678
Asset retirement obligations	1,741		33,329
Other current liabilities	15,172		21,573
Total current liabilities	280,134		522,916
Long-term debt	1,086,924		884,807
Asset retirement obligations	61,023		178,225
Other liabilities	48,167		45,691
Deferred income taxes	152,593		329,385
Total liabilities	1,628,841		1,961,024
Shareholders’ equity:
Common stock	6,286		6,455
Capital surplus	1,179,987		1,529,102
Retained earnings	30,013		217,293
Accumulated other comprehensive income (loss)	80,774		(18,220	)
Treasury stock, at cost	—		(50,108	)
Total shareholders’ equity	1,297,060		1,684,522
	$	2,925,901	3,645,546

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FOREST OIL CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended June 30,
	2006			2005
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales:
Natural gas	$	94,753		160,115
Oil, condensate, and natural gas liquids	115,470			109,240
Total oil and gas sales	210,223			269,355
Marketing, processing, and other	1,630			1,700
Total revenue	211,853			271,055
Operating expenses:
Lease operating expense	35,529			45,783
Production and property taxes	10,997			10,547
Transportation costs	5,642			4,583
General and administrative (including stock-based compensation of $2,498 and $154, respectively)	11,071			11,091
Depreciation and depletion	63,253			97,249
Accretion of asset retirement obligations	1,301			4,322
Impairment	2,078			—
Total operating expenses	129,871			173,575
Earnings from operations	81,982			97,480
Other income and expense:
Interest expense	17,340			16,061
Unrealized gains on derivative instruments, net	(14,378		)	(4,310	)
Realized losses (gains) on derivative instruments, net	13,698			(850	)
Other (income) expense, net	(110		)	2,509
Total other income and expense	16,550			13,410
Earnings before income taxes	65,432			84,070
Income tax expense:
Current	1,819			617
Deferred	6,565			31,252
Total income tax expense	8,384			31,869
Net earnings	$	57,048		52,201
Weighted average number of common shares outstanding:
Basic	62,195			61,419
Diluted	63,489			62,727
Basic net earnings per common share	$	0.92		0.85
Diluted net earnings per common share	$	0.90		0.83

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FOREST OIL CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended June 30,
	2006			2005
	(In thousands)
Cash flows from operating activities:
Net earnings	$	57,048		52,201
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and depletion	63,253			97,249
Accretion of asset retirement obligations	1,301			4,322
Impairment	2,078			—
Unrealized gains on derivative instruments, net	(14,378		)	(4,310	)
Deferred income tax expense	6,565			31,252
Stock-based compensation	2,498			154
Other, net	(841		)	758
Changes in operating assets and liabilities, net of effects of acquisition:
Accounts receivable	50			26,988
Other current assets	1,519			2,923
Accounts payable	(12,733		)	(6,210	)
Accrued interest and other current liabilities	(23,743		)	(15,987	)
Net cash provided by operating activities	82,617			189,340
Cash flows from investing activities:
Acquisition of subsidiary	—			(196,631	)
Capital expenditures	(147,663		)	(109,134	)
Proceeds from sales of assets	337			—
Other, net	(161		)	740
Net cash used by investment activities	(147,487		)	(305,025	)
Cash flows from financing activities:
Proceeds from bank borrowings	747,125			794,000
Repayments of bank borrowings	(718,199		)	(649,000	)
Repayment of bank debt assumed in acquisition	—			(35,000	)
Proceeds from Spin-off	21,670			—
Increase in bank overdrafts	11,582			—
Proceeds from the exercise of options and warrants and employee stock purchases	1,525			14,070
Other, net	(10		)	(757	)
Net cash provided by financing activities	63,693			123,313
Effect of exchange rate changes on cash	323			612
Net (decrease) increase in cash and cash equivalents	(854		)	8,240
Cash and cash equivalents at beginning of period	6,310			5,808
Cash and cash equivalents at end of period	$	5,456		14,048

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