Edgar Filing: MARINER ENERGY INC

Filed by Forest Oil Corporation

Pursuant to Rule 425 under the Securities Act of 1933

Subject Company: Mariner Energy, Inc.

File No. 333-129096

These materials are not a substitute for the registration statement that was filed with the Securities and Exchange Commission in connection with the transaction, or the proxy statement/prospectus-information statement to be mailed to stockholders. The registration statement has not yet been declared effective. Investors are urged to read the proxy statement/prospectus-information statement which will contain important information, including detailed risk factors, when it becomes available. The proxy statement/prospectus-information statement and other documents that will be filed by Forest and Mariner with the Securities and Exchange Commission will be available free of charge at the SEC’s website, www.sec.gov, or by directing a request when such a filing is made to Forest Oil Corporation, 707 17^th Street, Suite 3600, Denver, CO 80202, Attention: Investor Relations; or by directing a request when such a filing is made to Mariner Energy, Inc., 2101 CityWest Blvd., Bldg. 4, Ste. 900, Houston, TX 77042-2831, Attention: Investor Relations.

Mariner, Forest and their respective directors, and executive officers may be considered participants in the solicitation of proxies in connection with the proposed transaction. Information about the participants in the solicitation will be set forth in the proxy statement/prospectus-information statement when it becomes available.

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

FOR IMMEDIATE RELEASE

FOREST OIL ANNOUNCES THIRD QUARTER 2005 RESULTS;

ADJUSTED EBITDA AND CASH FLOW SET NEW RECORDS

• Forest has Record Adjusted EBITDA and Cash Flow

• Hurricane Activity in the Third Quarter Defers 6 Bcfe of Production

• Net Debt Decreases to $812 Million

• Record Canadian Wild River Gross Production at 49 MMcfe/d with 100% Success in the Quarter; Third Quarter Sequential Production Rates Up 36%

• Record Buffalo Wallow Net Production at 32 MMcfe/d with 100% Success in the Quarter; Third Quarter Sequential Production Rates Up 10%

• First Greater Haley Area Well Successful; 2 More to TD in the Fourth Quarter

DENVER, COLORADO – November 9, 2005 - Forest Oil Corporation (NYSE:FST) (Forest or the Company) today announced results for the third quarter and first nine months of 2005. In the third quarter of 2005 compared to the third quarter of 2004, the Company had the following highlights:

• Record adjusted EBITDA of $190 million, an increase of 11%

• Net cash flow from operations, exclusive of working capital items, was $174 million, an increase of 13%

• Net debt was $812 million, a decrease of 14%

Also during the quarter, Forest announced on September 12, 2005 that it intends to spin-off to Forest shareholders its offshore Gulf of Mexico operations, and that the Gulf of Mexico operations would immediately thereafter be acquired in a merger transaction by Mariner Energy, Inc. (Mariner). Mariner has filed Form S-4 with the Securities Exchange Commission which is currently under review. After the spin-off and merger, Mariner will be a separately traded public company that will own and operate the combined businesses of Mariner and Forest’s offshore Gulf of Mexico operations. The transaction is expected to be non-taxable to Forest and its shareholders and is anticipated to close in the first quarter of 2006.

H. Craig Clark, President and CEO, stated, “Despite the deferral of approximately 6 Bcfe of production due to the hurricanes in the third quarter, Forest was able to post another record quarter for adjusted EBITDA and cash flow. Strong cash flow was generated from our onshore business units which now comprise over 75% of our reserve base. As a result of the strong performance in our onshore business units, we will continue to increase activity onshore in the fourth quarter and thereafter. We continue to see excellent momentum in our key onshore fields including significant production increases in our resource plays, Buffalo Wallow and Wild River, and positive results in our first well in the Greater Haley Area. Finally, we continue to work towards the closing of our Gulf of Mexico combination with Mariner Energy and see the spin-off as a strategic value creator for our shareholders.”

THIRD QUARTER 2005 RESULTS

For the quarter ended September 30, 2005, Forest reported net earnings of $3.3 million or $.05 per basic share. This amount compares to net earnings of $31.8 million or $.54 per basic share in the corresponding 2004 period. Net earnings in the third quarter of 2005 were adversely affected by the following items:

• Accounting regulations required Forest to take a pre-tax, non-cash charge of $72.1 million including $42.8 million associated with the discontinuance of hedge accounting related to 2005 hedges on Hurricane Katrina and Rita production deferrals, $23.0 million of unrealized losses related to several collar agreements that did not qualify for cash flow hedge accounting, and measured hedge ineffectiveness of $6.3 million

• A pre-tax charge of $3.6 million to establish a reserve for insurance surcharges related primarily to Hurricane Katrina

Without the effect of these items, Forest’s adjusted net earnings would have been $50.2 million, or $.81 per basic share. These amounts compare to adjusted net earnings of $34.0 million or $.58 per basic share in the corresponding 2004 period computed on a comparable basis.

For the third quarter of 2005, Forest’s sales volumes were 435.8 MMcfe/d or a decrease of 14% compared to the third quarter of 2004; hurricanes in the third quarter of 2005 deferred approximately 6 Bcfe (65 MMcfe/d). The Company’s adjusted EBITDA increased 11% compared to the third quarter of 2004 to $190.5 million, despite the 14% decrease in production from hurricanes, due to higher per unit netbacks (oil and gas sales revenue less lease operating expenses, production and property taxes, and transportation costs).

At September 30, 2005, net debt decreased 14% to $812 million compared to $945 million at September 30, 2004. The year-over-year decrease in net debt was primarily due to the internally generated free cash flow and property sales during this period, offset by additional debt incurred for the acquisition of the Buffalo Wallow field in the second quarter of 2005. The Company had a net debt to book capitalization of 35% at September 30, 2005 compared to 41% at September 30, 2004.

NINE MONTHS ENDED SEPTEMBER 30, 2005 RESULTS

For the nine months ended September 30, 2005, Forest reported net earnings of $94.3 million or $1.54 per basic share. This amount compares to net earnings of $79.0 million or $1.41 per basic share in the corresponding 2004 period. Net earnings for the nine months ended September 30, 2005 were adversely affected by the following items:

• Accounting regulations required Forest to take a pre-tax, non-cash charge of $74.4 million including $42.8 million associated with the discontinuance of hedge accounting related to 2005 hedges on Hurricane Katrina and Rita production deferrals, $26.1 million of unrealized losses related to several collar agreements that did not qualify for cash flow hedge accounting, and measured hedge ineffectiveness of $5.5 million

• A pre-tax charge of $4.0 million to establish a reserve for insurance surcharges related primarily to Hurricane Katrina

• A pre-tax, non-cash charge of $2.9 million primarily due to the impairment of properties related to our exit from Romania

• A pre-tax, non-cash charge of $2.2 million representing our 40% share of a valuation allowance that Cook Inlet Pipeline Company (CIPC) recorded against a portion of its deferred tax assets

Without the effect of these items, Forest’s adjusted net earnings would have been $146.1 million, or $2.39 per basic share. These amounts compare to adjusted net earnings of $82.1 million or $1.46 per basic share in the corresponding 2004 period computed on a comparable basis.

For the nine months ended September 30, 2005, Forest’s sales volumes were 475.1 MMcfe/d or an increase of 3% compared to the corresponding period in 2004 despite storm related downtime in 2005. The Company’s adjusted EBITDA increased 29% compared to the corresponding period in 2004 to $575.2 million, due to the increased production and higher per unit netbacks.

CAPITAL ACTIVITIES

In the third quarter of 2005, Forest invested $150 million in exploration and development activities. The following table summarizes capital expenditures incurred in the third quarter of 2005 for exploration, development and acquisition activities (in millions). The amounts have been split between the assets which are subject to the merger agreement with Mariner (Spinco) and those which are not (Remainco):

	U.S. Remainco		Canada	International	Total Remainco	Spinco	Total
Exploration	$	9	9	1	19	15	34
Development	66		23	—	89	27	116
Acquisitions	—		—	—	—	—	—

Total	$	75	32	1	108	42	150

For the nine months ended September 30, 2005, Forest invested $224 million on acquisitions, excluding the deferred tax step-up in booked fair value for the Buffalo Wallow assets, $343 million in exploration and development activities, and received $24 million from asset dispositions. Total costs incurred included a non-cash gross up of $89 million relating to the deferred tax step-up in the booked fair value of the assets acquired in the Buffalo Wallow acquisition. The following table summarizes capital expenditures incurred in the nine months ended September 30, 2005 for exploration, development and acquisition activities (in millions):

	U.S. Remainco		Canada	International	Total Remainco	Spinco	Total
Exploration	$	30	26	2	58	48	106
Development	136		44	—	180	57	237
Acquisitions	216		8	—	224	—	224

Total	382		78	2	462	105	567
Add:
Step-up in booked fair value of Buffalo Wallow assets	89		—	—	89	—	89

Total	$	471	78	2	551	105	656

CERTAIN COMPARATIVE FINANCIAL AND OPERATING DATA

The following table sets forth certain of Forest’s financial and operating data for the three and nine months ended September 30, 2005 and 2004. The amounts have been split between the assets which are subject to the merger agreement with Mariner (Spinco) and those which are not (Remainco). Forest estimates that 0.4 Bcfe (5 MMcfe/d) of the 6 Bcfe (65 MMcfe/d) of deferred production in the quarter due to hurricanes was attributable to Remainco properties.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005			2004	2005	2004
Daily natural gas sales volumes (MMcf):
U.S. Remainco	91.4			87.5	90.9	81.4
Canada	52.4			53.1	50.1	41.2
Total Remainco	143.8			140.6	141.0	122.6

Spinco	124.4			185.3	151.8	168.0
Total	268.2			325.9	292.8	290.6

Daily liquids sales volumes (MBbls):
U.S. Remainco	17.4			16.6	17.8	17.1
Canada	3.3			4.7	3.5	3.3
Total Remainco	20.7			21.3	21.3	20.4

Spinco	7.3			8.7	9.1	8.0
Total	28.0			30.0	30.4	28.4

Equivalent daily sales volumes (MMcfe):
U.S. Remainco	195.0			187.3	197.8	183.8
Canada	72.4			81.2	71.1	60.7
Total Remainco	267.4			268.5	268.9	244.5

Spinco	168.4			237.3	206.2	216.0
Total	435.8			505.8	475.1	460.5

Total equivalent sales volumes (Bcfe)	40.1			46.5	129.7	126.2

Oil and gas sales revenue (millions) (1)
U.S. Remainco	$	125.8		83.8	350.5	249.4
Canada	48.0			35.9	117.2	72.9
Total Remainco	173.8			119.7	467.7	322.3

Spinco	92.4			125.3	326.7	324.4
Total	$	266.2		245.0	794.4	646.7

Average gas sales price (per Mcf) (1)	$	6.33		5.25	5.89	5.18

Average liquids sales price (per Bbl) (1)	$	42.83		31.75	39.03	30.16

Costs (per $ Mcfe):
Lease operating expenses	1.29			1.13	1.12	1.14
Production and property taxes	.27			.18	.24	.18
Transportation costs	.11			.09	.11	.09
General and administrative expense	.25			.17	.24	.18
Interest expense	.39			.36	.36	.34
Current income tax expense	(.01		)	.01	.02	.01

Capital expenditures (millions):
Exploration and development	$	150		53	343	194
Acquisitions(2)	—			19	313	383
Total	$	150		72	656	577

(1) Includes effects of hedging.

(2) Includes a deferred tax gross up of approximately $89 million and $51 million for the nine month periods ended September 30, 2005 and 2004, respectively.

FINANCIAL AND OPERATIONAL RESULTS

For the three and nine month periods ended September 30, 2005, oil and gas sales volumes decreased approximately 14% and increased approximately 3%, respectively, compared to the corresponding periods in 2004. The three month decrease was caused by the deferral of offshore Gulf of Mexico and Gulf Coast onshore production of approximately 6 Bcfe due to hurricanes in the third quarter of 2005. The nine month increase was due primarily to acquisitions of producing properties made in April 2005 and June 2004 (net of approximately $104 million of property dispositions) offset by the deferrals related to the hurricane activity in the third quarter of 2005. Increased oil and gas revenue of 9% and 23% in the three and nine months ended September 30, 2005 compared to the corresponding periods in 2004, respectively, was due to increased net price realizations for oil and natural gas.

Oil and gas production expense increased in the three and nine months ended September 30, 2005 compared to the corresponding periods of 2004. Most of the increase was from hurricane related costs and production and property taxes. The components of oil and gas production expense were as follows:

Production Expense by Component

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005		Per Mcfe	2004	Per Mcfe	2005	Per Mcfe	2004	Per Mcfe
	(In Thousands, except per unit amounts)
Direct operating expense and overhead	$	43,727	1.10	48,366	1.04	122,817	.94	128,785	1.02
Hurricane repairs	919		.02	—	—	976	.01	—	—
Workovers	6,930		.17	4,035	.09	21,426	.17	15,673	.12
Transportation costs	4,597		.11	4,368	.09	14,352	.11	11,788	.09
Production and property taxes	10,914		.27	8,274	.18	31,358	.24	22,817	.18

Total	$	67,087	1.67	65,043	1.40	190,929	1.47	179,063	1.41

Production Expense Remainco versus Spinco

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005		Per Mcfe	2004	Per Mcfe	2005	Per Mcfe	2004	Per Mcfe
	(In Thousands, except per unit amounts)
Remainco
U.S.	$	37,479	2.09	35,197	2.04	108,061	2.00	98,742	1.96
Canada	6,713		1.01	7,862	1.05	21,005	1.08	14,632	.88

Total Remainco	44,192		1.80	43,059	1.74	129,066	1.76	113,374	1.69

Spinco	22,895		1.48	21,984	1.01	61,863	1.10	65,689	1.11
Total	$	67,087	1.67	65,043	1.40	190,929	1.47	179,063	1.41

Lease operating expenses (LOE), which includes direct operating expense and overhead, hurricane repairs, and workovers, decreased to $51.6 million for the quarter ended September 30, 2005 or 2% from $52.4 million for the corresponding period in 2004. On a per-unit basis, LOE increased to $1.29 per Mcfe or 14% during the third quarter 2005 compared to the prior year’s third quarter. For the nine month period ended September 30, 2005, LOE on a per-unit basis decreased 2% to $1.12 per Mcfe from $1.14 per Mcfe in the corresponding 2004 period. The increase in LOE on an equivalent Mcfe basis for the three months ended September 30, 2005 is primarily due to the deferral of offshore Gulf of Mexico production due to the hurricane activity in the third quarter of 2005. The 2% decrease in LOE on an equivalent Mcfe basis for the nine months ended September 30, 2005 is primarily a result of cost control efforts as announced in the third quarter of 2004 which have more than offset increases in service and material costs and the effects of the deferred production in the Gulf of Mexico.

Production and property taxes increased by $2.6 million or 32% during the third quarter 2005 compared to the prior year’s third quarter. For the nine month period ended September 30, 2005, production and property taxes increased by 37% compared to the prior year period. The three and nine month increases were attributable to higher commodity prices. As a percentage of oil and natural gas revenue, excluding hedging losses, production and property taxes for the three and nine month periods ended September 30, 2005 were 3.3% and 3.4%, respectively, and in the comparable periods of 2004 were 3.0% and 3.1%, respectively. The increased rate is a result of a greater percentage of our production coming from onshore U.S. fields in 2005 as compared with 2004.

General and administrative expense increased 23% to $9.8 million for the quarter ended September 30, 2005 compared to $8.0 million for the corresponding period in 2004. For the nine months ended September 30, 2005, general and administrative expense increased 41% to $31.7 million compared to $22.5 million for the corresponding period in 2004. The three month increase resulted primarily from increased headcount due to acquisition activities which was partially offset by an increase in our overhead capitalization rate from 41% for the three month period ended September 30, 2004 to 42% for the corresponding period in 2005. The nine month increase resulted primarily from increased headcount due to acquisition activities and a decrease in our overhead capitalization rate from 43% for the nine month period ended September 30, 2004 to 38% for the corresponding period in 2005. Combined capitalized and expensed overhead costs increased by 26% for the comparable quarter and by 29% in the comparable nine month period.

Depreciation and depletion expense decreased to $91.0 million for the quarter ended September 30, 2005 from $94.6 million for the corresponding period in 2004. On a per-unit basis, the depreciation and depletion rate was $2.27 per Mcfe for the quarter ended September 30, 2005 compared to $2.03 per Mcfe in the corresponding period in 2004. For the nine month period ending September 30, 2005, depreciation and depletion expense increased to $284.6 million from $257.7 million for the comparable period in 2004. On a per-unit basis, the depreciation and depletion rate was $2.19 per Mcfe for the first nine months of 2005 compared to $2.04 per Mcfe in the corresponding period in 2004. The increase for the three and nine months ended September 30, 2005 as compared to the corresponding periods in the prior year are primarily due to higher anticipated drilling and completion costs on future development activities.

For the nine months ended September 30, 2005, other expense includes a charge of $2.2 million representing our 40% share of a valuation allowance that CIPC recorded in June 2005 against a portion of its deferred tax assets.

HEDGING

Forest currently has hedges in place for the remainder of 2005 and 2006 covering the aggregate average daily volumes and weighted average prices shown below. The majority of the volumes hedged for 2005 and 2006 are associated with Forest’s acquisition activities. The hedges have been split between the hedges which are subject to the merger agreement with Mariner (Spinco) and those that are not (Remainco) and include all Forest hedges, both effective and ineffective. The Spinco hedges will be assumed by Mariner at the time of the merger.

	Remainder of 2005 Remainco			Remainder of 2005 Spinco		2006 Remainco		2006 Spinco
Natural gas swaps:
Contract volumes (BBtu/d)	48.4		(2)	55.0	(2)	10.0	(1)	40.0	(1)
Weighted average price (per MMBtu)	$	5.33		4.88		5.51		6.15

Natural gas collars:
Contract volumes (BBtu/d)	43.4		(1)	—		50.0		—
Weighted average ceiling price (per MMBtu)	$	7.17		—		11.88		—
Weighted average floor price (per MMBtu)	$	5.85		—		7.43		—

Oil swaps:
Contract volumes (MBbls/d)	8.5		(2)	—		4.0	(1)	—
Weighted average price (per Bbl)	$	35.42		—		31.58		—

Oil collars:
Contract volumes (MBbls/d)	1.0		(1)	—		5.5	(2)	—
Weighted average ceiling price (per Bbl)	$	47.30		—		65.87		—
Weighted average floor price (per Bbl)	$	42.00		—		46.73		—

Oil three-way collars:
Contract volumes (MBbls/d)	1.5			—		—		—
Weighted average ceiling price (per Bbl)	$	32.00		—		—		—
Weighted average floor price (per Bbl)	$	28.00		—		—		—
Three-way weighted average floor price (per Bbl)	$	24.00		—		—		—

(1) Represents hedged volumes associated with Forest’s acquisition activities.

(2) 100.0 of the 103.4 BBtu/d of hedged natural gas volumes and 6.5 of the 8.5 MBbls/d of hedged oil swap volumes in 2005 are associated with Forest’s acquisition activities. 1.0 of the 5.5 BBtu/d of hedged natural gas collar volumes in 2006 are associated with Forest’s acquisition activities.

OPERATIONAL PROJECT UPDATE

Western Business Unit

Buffalo Wallow, Texas Panhandle (66-100% Working Interest) – During the third quarter, Forest completed 14 wells with a 100% success rate and had 7 wells in progress on September 30, 2005 including activity in offset areas. A total of 25 wells have been drilled since acquiring this property in April 2005. Initial rates in the third quarter ranged from 1.4 to 3.8 MMcfe/d and averaged 2.7 MMcfe/d. Additional fracture treatment stages and deeper Atoka pay have contributed to the higher than anticipated initial rates. Current net production is approximately 32 MMcfe/d, an increase of approximately 60% from the acquisition net production rate of 20 MMcfe/d.

Greater Haley Area, West Texas (93-100% Working Interest) – In the Greater Haley Area, Forest’s first completion had an initial rate of 5.0 MMcfe/d. Two wells are drilling and are expected to reach total depth in the fourth quarter. Two additional recompletions/re-entries are planned in the fourth quarter. Our acreage position has been increased to approximately 30,000 net acres.

SE New Mexico Exploration Program (6-50% Working interest) – A total of 12 gross wells have been completed in 2005 at an 83% success rate. Initial rates have averaged 1.9 MMcfe/d. Forest has recently increased its acreage position to approximately 6,400 acres in this area.

Central Midland Basin, Texas Exploitation (25-100% Working interest) – A total of 21 wells have been drilled year to date at a 100% success rate. Most of these projects are located in the Martin, Fullerton, Dune and Tex-Mex Fields. Activity will be increased in these areas using Forest-owned rigs. There are approximately 150 potential drilling locations identified in this area. Initial production rates range from 270 Mcfe/d to 2.2 MMcfe/d.

Canada Business Unit

Wild River Area, Alberta, Canada (24-100% Working Interest) – The Wild River area continues to be our most active area in Canada with gross production reaching a record of 49 MMcfe/d in the third quarter. This is a 36% increase in production since the second quarter of 2005, and 188% since the beginning of the year. A total of 26 wells have been drilled year to date with a 100% success rate. There are currently 4 wells which have been drilled and are awaiting completion or pipeline connection.

Southern Business Unit

Sabine Prospect, Calcasieu Parish, Louisiana (45% Working Interest) – The Olympia 9-1, the fifth exploration well was cased and tested at rates of 1.1 MMcfe/d. The sixth well is currently drilling with one additional well planned in the fourth quarter of 2005. Forest has approximately 157,000 gross acres in this area.

Gulf of Mexico

Eugene Island 53 (64% Working Interest) – The EI 53 G-1 was completed and was tied to sales in October. The current rate from this dual completion is 15.7 MMcfe/d.

Brazos Block 491 (100% Working Interest) – The BR 491 #4 well was tied to sales late in the third quarter at an initial rate of 7.7 MMcfe/d.

Vermilion Block 102 (100% Working Interest) – Two wells were drilled and tested in the third quarter. The VR 102 A-3 had an initial rate of 5.1 MMcfe/d and the VR 102 A-5 tested at 3.0 MMcfe/d. Both wells will be on line in the fourth quarter of 2005.

Vermilion Block 14/26 Field (100% Working Interest) – The VR 26 #52 recompletion tested at 12.5 MMcfe/d.

Alaska Business Unit

Onshore Cook Inlet Gas Exploration Program (30-100% Working Interest) – Interconnect and facilities construction were completed and first sales began in November 2005 under a new gas supply arrangement. Sales from additional wells which are planned in 2005 and 2006 will also be sold under this arrangement. Currently, gas sales in Alaska are 8.0 MMcfe/d.

There are currently two wells in progress in the West Foreland area and one delineation well being drilled at Three Mile Creek. It is anticipated that an additional exploratory well will be spud this year at the Middle Lake prospect as well as another Three Mile Creek delineation well.

HURRICANE UPDATE

Forest had approximately 180 MMcfe/d of production shut-in in the Gulf Coast Region on October 1, 2005, due to the third quarter hurricanes. Forest estimates that current shut-in production is approximately 100-110 MMcfe/d. The majority of the production that remains shut-in is due to third-party processing facilities and infrastructure. The timetable for restoring full production is uncertain as it is dependent on repairs to transportation and processing facilities which are owned by others. Forest estimates that total production deferred during the fourth quarter of 2005 for Hurricanes Katrina and Rita will be approximately 10 Bcfe, of which 0.6 Bcfe pertains to Remainco properties.

2005 GUIDANCE

Forest first announced its 2005 guidance on February 16, 2005, updated guidance on April 4, 2005, and reported initial hurricane damage assessments on September 30, 2005. Due to the substantial impact of the third quarter hurricanes on the Company’s operations, new guidance for 2005 is disclosed below. The following update is made subject to the following cautionary statements and limitations:

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 difference 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, meteorological events including, but not limited to, hurricanes, earthquakes, and numerous other factors. 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.

Forest has completed several major property acquisitions and dispositions in recent years, and has a pending transaction involving the spin-off and merger of the offshore Gulf of Mexico operation. The following forward-looking data excludes the financial and operating effects of potential property acquisitions or divestitures during 2005 and does not include the effects of the pending spin-off and merger transaction. The timing and ultimate results of such acquisition and divestiture activity is difficult to predict, and may vary materially from current plans and expectations.

Given these general limitations and those discussed below, the following is a summary of Forest’s updated guidance for 2005:

Daily Production. We estimate that our daily production will be in the range of 450 to 460 MMcfe/d for the full year of 2005.

Liquids Production. We estimate that our 2005 production of oil and natural gas liquids will be between 28,000 and 30,000 Bbls/d.

Gas Production. We estimate that our 2005 natural gas production will be between 275 and 285 MMcf/d.

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 expect that our 2005 production expense, including hurricane repairs and insurance retentions, will be between $255 million and $265 million.

General and Administrative Expense (G&A). We estimate that due to our lower than expected capitalization rate our 2005 G&A expense will be between $40 million and $44 million.

Depreciation, Depletion and Amortization (DD&A). We estimate that our DD&A rate will be between $ 2.20 and $2.30 per Mcfe during 2005.

Capital Expenditures. We estimate that expenditures for exploration and development will be between $475 million and $500 million in 2005. Some of the factors impacting the level of capital expenditures in 2005 include the cost and availability of oil field services, weather disruptions and installations delayed for hurricanes.

NON-GAAP FINANCIAL MEASURES

In addition to reporting net earnings as defined under GAAP, Forest also presents adjusted EBITDA, which consists of net earnings plus interest expense, income tax expense, depreciation and depletion, accretion of asset retirement obligation, retrospective insurance costs, unrealized losses on derivatives, impairment of oil and gas properties, and change in deferred tax valuation allowance of equity method investee (CIPC). 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. Adjusted EBITDA should not be considered as an alternative to net earnings as defined by GAAP. The following is a reconciliation of net earnings to adjusted EBITDA (in thousands):

	Three Months Ended September 30,			Nine Months Ended September 30,
	2005		2004	2005	2004
Net earnings	$	3,265	31,775	94,337	78,967
Interest expense	15,664		16,604	46,224	42,635
Income tax expense	516		20,367	53,631	49,812
Depreciation and depletion	91,029		94,583	284,554	257,685
Accretion of asset retirement obligation	4,352		4,472	12,951	12,900
Retrospective insurance costs	3,552		—	4,002	—
Unrealized losses on derivatives	72,095		3,584	74,365	3,367
Impairment of oil and gas properties	—		—	2,924	1,690
Change in deferred tax valuation allowance of equity method investee (CIPC)	—		—	2,167	—
Adjusted EBITDA	$	190,473	171,385	575,155	447,056

Forest presents net cash flow from operations, exclusive of working capital items, which consists of net cash provided by operating activities excluding changes in accounts receivable, other current assets, and accounts payable and accrued expenses. Management uses this measure to assess the Company’s ability to generate cash to fund exploration and development activities. Management interprets trends in this measure in a similar manner as trends in cash flow and liquidity. Net cash flow from operations, exclusive of working capital items should not be considered as an alternative to net cash provided by operating activities as defined by GAAP. Forest also presents free cash flow, which consists of net cash from operations, exclusive of working capital items less exploration and development capital expenditures. Management uses this measure to assess the Company’s ability to generate cash to repay debt and fund acquisitions. Management also interprets trends in this measure in a similar manner as trends in cash flow and liquidity. Free cash flow 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 net cash flow from operations, exclusive of working capital items and a reconciliation of net cash provided by operating activities to free cash flow (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005	2004
Net cash provided by operating activities	$	193,009		120,426		518,432	363,621
Changes in operating assets and liabilities:
Accounts receivable	21,390			(5,378	)	645	(29,629	)
Other current assets	5,280			(370	)	3,956	4,676
Accounts payable and accrued expenses	(45,688		)	38,760		67	61,180
Net cash flow from operations, exclusive of working capital items	$	173,991		153,438		523,100	399,848
Less: Exploration and development capital expenditures	149,939			53,105		343,441	194,153
Free cash flow	$	24,052		100,333		179,659	205,695

Forest presents adjusted net earnings, a financial measure that excludes certain items that management believes affect the comparability of operating results. Further, the timing and amounts of these items cannot be reasonably estimated and affect the comparability of operating results from period to period. Management uses this measure to evaluate the Company’s operational trends and performance relative to other oil and gas companies as well as with earnings estimates provided by securities analysts. Forest presents adjusted net earnings, which consists of net earnings plus unrealized losses on derivative instruments, retrospective insurance costs, impairment of oil and gas properties, changes in deferred tax valuation allowance of equity method invest (CIPC), and an income tax adjustment. Adjusted net earnings should not be considered as an alternative to net earnings as defined by GAAP. The following is a reconciliation of net earnings to adjusted net earnings (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005		2004
Net earnings	$	3,265		31,775		94,337		78,967
Unrealized losses on derivative instruments	72,095			3,584		74,365		3,367
Retrospective insurance costs	3,552			—		4,002		—
Impairment of oil and gas properties	—			—		2,924		1,690
Changes in deferred tax valuation allowance of equity method investee (CIPC)	—			—		2,167		—
Income tax adjustment for above items	(28,746		)	(1,362	)	(31,714	)	(1,922	)
Adjusted net earnings	$	50,166		33,997		146,081		82,102
Adjusted basic earnings per common share	$	.81		.58		2.39		1.46
Adjusted diluted earnings per common share	$	.79		.57		2.33		1.44

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 the Company’s indebtedness, based on actual principal amounts

owed and cash on hand which has not been applied to reduce the amounts of the credit facility. The following table sets forth the components of net debt as of September 30, 2005 and 2004 (in millions):

	September 30, 2005			September 30, 2004
	Principal		Book(1)	Principal	Book(1)

Credit facilities and bank debt	$	119	119	271	271
8% Senior notes due 2008	265		271	265	273
8% Senior notes due 2011	285		298	285	300
7³/₄% Senior notes due 2014	150		163	150	165
Total long-term debt	$	819	851	971	1,009
Cash and cash equivalents	7		7	26	26
Net debt	$	812	844	945	983

(1) Book amounts include the principal amount of long-term debt adjusted for unamortized gains on interest rate swaps of $26.7 million and $31.6 million at September 30, 2005 and 2004, respectively and an unamortized net premium on issuance of $5.8 million and $6.7 million at September 30, 2005 and 2004, respectively.

TELECONFERENCE CALL

Forest Oil Corporation management will hold a teleconference call on Thursday, November 10, 2005, at 12:00 pm MT to discuss the items described in this press release. If you would like to participate please call 1.800.399.6298 (for U.S./Canada) and 1.706.634.0924 (for International) and request the Forest Oil teleconference (ID # 1605103).

A replay will be available from Thursday, November 10 through November 17, 2005. You may access the replay by dialing toll free 1.800.642.1687 (for U.S./Canada) and 1.706.645.9291 (for International), conference ID # 1605103.

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 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 2004 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.

These materials are not a substitute for the registration statement that was filed with the Securities and Exchange Commission in connection with the spin-off transaction, or the proxy

statement/prospectus-information statement to be mailed to shareholders. The registration statement has not yet been declared effective. Investors are urged to read the proxy statement/prospectus-information statement which will contain important information, including detailed risk factors, when it becomes available. The proxy statement/prospectus-information statement and other documents that will be filed by Forest and Mariner with the Securities and Exchange Commission will be available free of charge at the SEC’s website, www.sec.gov, or by directing a request when such a filing is made to Forest Oil Corporation, 707 17^th Street, Suite 3600, Denver, CO 80202, Attention: Investor Relations; or by directing a request when such a filing is made to Mariner Energy, Inc., 2101 CityWest Blvd., Bldg. 4, Suite 900, Houston, TX 77042-2831, Attention: Investor Relations.

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 the Gulf of Mexico, Texas, New Mexico, Louisiana, Oklahoma, Utah, Wyoming and Alaska, 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 our website at www.forestoil.com.

November 9, 2005

FOREST OIL CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)

	September 30,			December 31,
	2005			2004
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	6,589		55,251
Accounts receivable	161,372			151,927
Current deferred tax asset	125,298			38,321
Other current assets	32,601			37,969
Total current assets	325,860			283,468

Net property and equipment	3,105,401			2,721,118

Goodwill	101,590			68,560
Other assets	39,845			49,359
	$	3,572,696		3,122,505

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	263,007		217,640
Derivative instruments	290,413			80,523
Asset retirement obligations	34,733			25,452
Total current liabilities	588,153			323,615

Long-term debt	851,480			888,819
Asset retirement obligations	177,116			184,724
Derivative instruments	42,832			20,890
Other liabilities	41,299			35,785
Deferred income taxes	344,514			196,525
Total liabilities	2,045,394			1,650,358
Shareholders’ equity:
Common stock	6,398			6,159
Capital surplus	1,498,191			1,444,367
Retained earnings	160,331			66,007
Accumulated other comprehensive (loss) income	(86,715		)	6,780
Treasury stock, at cost	(50,903		)	(51,166	)
Total shareholders’ equity	1,527,302			1,472,147
	$	3,572,696		3,122,505

FOREST OIL CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005			2004	2005	2004
	(In Thousands Except Per Share Amounts)
Revenue:
Oil and gas sales:
Natural gas	$	156,070		157,424	470,711	412,639
Oil, condensate and natural gas liquids	110,080			87,569	323,664	234,079
Total oil and gas sales	266,150			244,993	794,375	646,718
Processing and marketing income, net	2,086			400	5,207	1,406
Total revenue	268,236			245,393	799,582	648,124
Operating expenses:
Lease operating expenses	51,576			52,401	145,219	144,458
Production and property taxes	10,914			8,274	31,358	22,817
Transportation costs	4,597			4,368	14,352	11,788
General and administrative	9,847			7,975	31,694	22,504
Depreciation and depletion	91,029			94,583	284,554	257,685
Accretion of asset retirement obligation	4,352			4,472	12,951	12,900
Retrospective insurance costs and impairment of oil and gas properties	4,002			—	6,926	1,690
Total operating expenses	176,317			172,073	527,054	473,842
Earnings from operations	91,919			73,320	272,528	174,282
Other income and expense:
Interest expense	15,664			16,604	46,224	42,635
Unrealized losses on derivative instruments	72,095			3,584	74,365	3,367
Other expense (income), net	379			990	3,971	(350	)
Total other income and expense	88,138			21,178	124,560	45,652
Earnings before income taxes and discontinued operations	3,781			52,142	147,968	128,630
Income tax expense:
Current	(203		)	461	1,971	1,329
Deferred	719			19,906	51,660	47,759
Total income tax expense	516			20,367	53,631	49,088
Earnings from continuing operations	3,265			31,775	94,337	79,542
Loss from discontinued operations, net of tax	—			—	—	(575	)
Net earnings	$	3,265		31,775	94,337	78,967
Weighted average number of common shares outstanding:
Basic	61,946			59,019	61,198	56,058
Diluted	63,140			60,157	62,707	57,126
Basic earnings per common share:
Earnings from continuing operations	$	.05		.54	1.54	1.42
Loss from discontinued operations, net of tax	—			—	—	(.01	)
Net earnings per common share	$	.05		.54	1.54	1.41
Diluted earnings per common share:
Earnings from continuing operations	$	.05		.53	1.50	1.39
Loss from discontinued operations, net of tax	—			—	—	(.01	)
Net earnings per common share	$	.05		.53	1.50	1.38

FOREST OIL CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
	2005			2004
	(In Thousands)
Cash flows from operating activities:
Net earnings	$	94,337		78,967
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and depletion	284,554			257,685
Accretion of asset retirement obligation	12,951			12,900
Impairment of oil and gas properties	2,924			1,690
Unrealized losses on derivative instruments	74,365			3,367
Deferred income tax expense	51,660			48,481
Other, net	2,309			(3,242	)
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable	(645		)	29,629
Other current assets	(3,956		)	(4,676	)
Accounts payable and accrued expenses	(67		)	(61,180	)
Net cash provided by operating activities	518,432			363,621
Cash flows from investing activities:
Acquisition of subsidiaries	(196,645		)	(169,821	)
Capital expenditures for property and equipment:
Exploration, development and other acquisition costs	(351,488		)	(235,259	)
Other fixed assets	(9,659		)	(1,938	)
Proceeds from sales of assets	23,668			17,676
Sale of goodwill and contract value	—			8,493
Other, net	(4,273		)	(5,693	)
Net cash used by investing activities	(538,397		)	(386,542	)
Cash flows from financing activities:
Proceeds from bank borrowings	1,630,000			1,321,074
Repayments of bank borrowings	(1,663,000		)	(1,342,646	)
Repayments of bank debt assumed in acquisitions	(35,000		)	(66,354	)
Issuance of 8% senior notes, net of issuance costs	—			133,312
Redemption of 9 ½% senior notes	—			(126,971	)
Proceeds of common stock offering, net of offering costs	—			117,143
Proceeds from the exercise of options and warrants	41,806			11,666
Other, net	(1,723		)	(8,805	)
Net cash (used) provided by financing activities	(27,917		)	38,419
Effect of exchange rate changes on cash	(780		)	(1,434	)
Net (decrease) increase in cash and cash equivalents	(48,662		)	14,064
Cash and cash equivalents at beginning of period	55,251			11,509
Cash and cash equivalents at end of period	$	6,589		25,573

PATRICK REDMOND – FOREST OIL CORPORATION – IR

Good afternoon. I want to thank you for participating in our third quarter 2005 earnings conference call. We have joining us today Craig Clark, President and CEO, and Dave Keyte, Executive Vice President and CFO.

Before we get started I’d like to take a moment to advise you about our forward-looking statements within the meaning of Section 27-A of the Securities Act of 1933 and Section 21-E of the Securities and Exchange Act of 1934. These forward-looking statements are subject to all of the risks and uncertainties normally incident to the exploration, development, production and sale of oil and gas. We urge you to read our 2004 report on Form 10-K for a discussion of these risks that could cause our results and plans to differ materially from those in any forward-looking statements we may make today.

I will now turn the call over to Dave Keyte. Thank you.

DAVID H. KEYTE – FOREST OIL CORPORATION

Thanks, Pat.

First, I want to take this opportunity to congratulate Mike Kennedy in being promoted to Managing Director Capital Markets and Treasurer, although we will miss his stirring renditions of the cautionary statements on these calls, Pat Redmond, the new Director of Investor Relations, has been with us for years and has done a terrific job in financial analysis and insurance.

We are pleased to announce the quarterly results for Forest Oil. In the third quarter, records were set for EBITDA and cash flow on the financial front and record production levels at our two largest capital projects, the Buffalo Wallow field and Wild River in Alberta. Further, as Craig will discuss, there were important positive drilling developments in Haley and in our Alaska onshore gas play. Last, but certainly not least, we announced a spin-off transaction involving a merger of our Gulf operation and Mariner Energy. This transaction will result in a significant distribution to our shareholders and the creation of two excellent, but distinctly different, investment vehicles.

Mariner Transaction

First, progress on the spin-off. On September 12, 2005 we announced the spin-off to Forest shareholders of our offshore Gulf of Mexico operations, and that the Gulf of Mexico operations would immediately be acquired in a merger transaction by Mariner Energy, Inc. Mariner filed a Form S-4 with the Securities Exchange Commission on October 18, which is currently under review by the

SEC. We expect initial SEC comments in the next couple of weeks. Approximately one month after the proxy is cleared by the SEC, the Mariner shareholders will vote on the transaction. If approved, after the spin-off and merger, Mariner will be a separately traded public company that will own and operate the combined businesses of Mariner and Forest’s Gulf of Mexico operations. The transaction is expected to be non-taxable to Forest and its shareholders and we look forward to working with Mariner to close likely in the first quarter of 2006. Hurricanes appear to have had a similar effect on both Spinco and Mariner in terms of expected ‘05 results. For both companies, 2005 production forecasts have decreased since the transaction was announced due to production deferrals, but higher prices have cushioned the cash flow impacted. We continue to see this transaction as a significant strategic value creator to our shareholders, creating two “best in class” companies, Mariner with a track record of very successful exploration in deepwater, shelf, and deep shelf and Forest with a focus on its onshore assets developing resource plays and a continuance of its highly successful acquire and exploit strategy.

Production

In the third quarter, production was 436 MMCFE/d, down 14% over the third quarter of 2004 as a result of hurricanes in the Gulf of Mexico that deferred 6 Bcfe (65 MMcfe/d) in the third quarter of 2005. Spinco (the assets involved in the Mariner merger) produced 168 MMcfe/d, while Remainco (the remaining Forest assets) produced 268 MMcfe/d. Shut-in production was approximately 60 MMcfe/d in Spinco and 5 MMcfe/d in Remainco. During the quarter, we had record net production in Buffalo Wallow at about 32 MMcfe/d and Wild River at about 20 MMcfe/d, both up dramatically from the second quarter.

As previously announced, 180 MMcfe/d was shut in on October 1 as a result of hurricanes, and approximately 100-110 MMcfe/d is currently shut in. We

are expecting approximately 10 Bcfe of production in the 4^th quarter relating to the 3^rd quarter storms will be deferred. Craig will detail the deferrals. We estimate the split of fourth quarter production deferral between Spinco and Remainco to be 7 MMcfe/d in Remainco and 102 MMcfe/d in Spinco.

Earnings

Earnings for the quarter, adjusted for mark-to-market hedge losses and retrospective insurance premiums, were about $50 million or $.81 per basic share, as compared with $34 million in the previous year’s quarter, a 48% increase in earnings. Overall, higher top line revenue from higher prices offset increased costs in LOE, G&A, and DD&A. The impact from the hurricane was significant not only in reducing revenue from lost volumes, but increasing per unit costs in LOE and G&A.

Unrealized loss from derivatives was $73 million in the quarter. The main components are:

1.	Hedges designated in the third quarter as ineffective due to shut-in production at designated index sales points.	$	43 million

2.	Mark-to-market on hedges previously designated as ineffective.	$	23 million

3.	Measure in effectiveness on cash flow hedges in the quarter, primarily on oil.	$	7 million

Of this amount, $50 million will be recorded as an unrealized gain in derivatives in the fourth quarter and the actual settlement will be a realized gain or loss in the other income line item. I know this makes for a messy income statement, but unfortunately this is the FAS 133 framework that is supposed to provide clarity to our shareholders.

Revenue

Price realizations, net of hedges, increased 26% to $6.64 from $5.27 per MCFE as a result of a significant increase in commodities prices in the 3^rd quarter of 2005, to record levels. Realized prices were impacted by hedging losses of $1.60 per MCFE in the 3^rd quarter of 2005 versus $0.65 per MCFE in the 3^rd quarter of 2004. In the third quarter, liquids differentials continued to widen from $8.79 to $9.64, oil differentials widened 50¢ to $4.25, while NGL realizations stayed flat at 52% of NYMEX.

LOE

Direct operating expense continues to come in below 2004 levels, but due to hurricane related production shortfalls, on a per unit basis during the quarter, direct LOE was up 5% to $1.10 per unit, along with a 41% increase in production taxes and transportation. For the first nine months of the year, direct LOE is down 8% per unit, offsetting the 30% increase in production taxes and transportation. Lease operating expenses per unit were up due to deferral of production volumes from hurricanes. Spinco production costs were averaging $1.26 in July and August and jumped to $2.17 in September. Southern (the Gulf Coast portion of Remainco) was averaging $1.62 in July and August and jumped to $2.32 in September. While certainly production expense is both variable and fixed in nature, this is not true for spikes. Crews are still employed, boats and helicopters still run, supplies still flow, and contracts still exist during the deferral period. While these costs are certainly variable, they are inelastic in the short-term. While per unit amounts are up, this is an area of considerable out-performance for the Company and gives us further confidence that we will be able to make necessary changes in our cost structure in 2006 to right size for Remainco.

G&A

Expensed G&A was up in the quarter over 2004 as we have added personnel to support acquisition and increased capital activity in the last 12 months. Total costs were up 35% to $18.1 million from $13.5 million in 2004. It looks like this line item will be our cost challenge in 2006 as we continue to attempt to manage labor costs and as we make adjustments for Remainco operations.

EBITDA/Cash Flow

EBITDA was $190 million for the quarter, up 11% from last year’s record, driven by higher realizations. Cash flow was up 37% to $174 million or about $2.81 per share. Despite deferring 6 Bcfe or an estimated $40 million of revenue in the quarter, we still generated almost $25 million of free cash flow or 4% of our equity market cap on an annualized basis. We estimate that by year-end, despite deferring 16 Bcfe or an estimated $100 million of revenue, we will have generated sufficient free cash flow to pay off our Buffalo Wallow acquisition in less than a year.

Capital Activities

Our DD&A rate for the quarter was $2.27 per MCFE, which is an increase from prior quarters. Due to increases in service costs that we are experiencing, we have increased our estimated future development costs, which is part of the depletion calculation. As suggested in the prior teleconference call, we have accelerated our capital spending in the second half of the year. Results of capital spending, particularly in Canada and Western, have been good to date.

Debt

Net debt finished the quarter at $812 million, which is only $15 million more than at the beginning of last year. Our leverage was decreased to 35% from slightly over 40% on April 1. Given our outlook and current price levels, we think breaking through $1 billion in revenue will be achieved in 2005, and based on this, despite hurricane impacts, our year-end debt goal of $750 million may still be achievable.

Recently we announced that the Credit Facility had been amended to allow our spin-off transaction for no cost to Forest. In addition, the bank group confirmed an initial BB of $600 million for Remainco. We expect nothing to be drawn on that facility upon closing the Mariner transaction.

Summary

In summary, the quarter was another solid performance for Forest despite the devastation caused by the hurricanes:

1. Record third quarter on our cash flow measures;

2. We announced a very significant and valuable distribution to our shareholders;

3. Free cash flow generation continued and was 4% of equity value on annualized basis;

4. The Company continued its focus on costs continuing to deliver good performance on this measure, against industry trend.

5. Drilling investments have been productive and investment activity has now begun to increase.

The business model continues to work and work well, providing good performance and value creation to our investors well within our cash flow, even in the face of historic storm events.

Over to Craig……

3^rd QTR 2005

CONFERENCE CALL

C. Clark Remarks

Thanks Dave, the third quarter, was certainly eventful with all of the hurricanes in the Gulf of Mexico. But despite dodging hurricanes, we got a lot accomplished in terms of positioning Forest Oil for the future. We spent most of the 3^rd quarter of 2005 on the negotiation of our spin-off of our GOM operations to Mariner Energy, Inc. We have been on the road since Mid-September to provide the details of this transaction to shareholders. We continue to work towards the closing of the GOM transaction which is estimated to close in the First quarter of 2006. As stated on our September conference call, we believe this spin-off is an innovative transaction which creates value for our shareholders. We have done pretty much a 180° turnaround in Forest over the past 2 years, so now we turn our attention to growing the remaining portfolio, or Remainco, and as noted in yesterday’s press release we’re off to a good start with the drilling operations projects noted.

In addition to my usual comments regarding our operations projects, I will focus on our costs, specifically drilling and LOE, the details of our hurricane impacts and the multi-well plays within Remainco as we ramp up activity on our onshore properties including some of the places we’ve added to our solid acreage position in some areas recently. Dave covered our financials and the details of the hedge accounting. I’m a little disappointed in all the noise this quarter, but am pleased with us hitting our cash flow per share while maintaining our capex discipline and debt objectives.

In terms of production, we were down the middle of our expectations with the only adjustment being the hurricanes. I should note that Hurricane Katrina and particularly Hurricane Rita effected onshore production as well in the quarter yet we are on track with the Remainco production which averaged 268 MMcfe/d in the 3^rd quarter despite 5 MM/D deferred from hurricanes. The Remainco production is flat with a year ago despite selling $130 MM in marginal properties since late 2004 and the hurricane deferral. We expect to see organic growth from these properties in the 4^th quarter and into 2006. You can also finally see the GOM projects come on line as noted in the press release which were delayed from the previous quarter which should give Mariner a good start once third party facilities are restored.

The 4 main components for our 4^th quarter production growth in the Remainco properties will be from Buffalo Wallow, the Haley Atoka activity, new well pipeline tie-ins in Canada and more Alaska gas sales.

In terms of a hurricane update, let me try and give you a status report as we continue to survey the third parties and other operators who affect us. We evacuated or shut in production for 7 hurricanes. As mentioned before we had no major rig damage or rigs blown off location. We lost 6 platforms, 3 operated and 3 non-operated which produce 6 MMcfe/d net. All of these were minimal or satellite structures. Our current shut-in production from the hurricanes is 100-110 MMcfe/d. In addition to 6 MMcfe/d noted above from lost platforms, the shut-in production breaks down as follows:

12 MMcfe/d is shut-in awaiting repairs by Forest

18 MMcfe/d is waiting on repairs by other operators

70 MMcfe/d is awaiting 3^rd party pipelines or onshore processing plants or oil facilities.

So therefore, over 80% of our shut-ins are waiting on others. We expect to be near full rate in the first quarter of 2006 but our estimates are based on the information received from the pipeline, plants etc. Forest was very fortunate in terms of losses compared to others. As previously mentioned, we are insured for losses above $5 MM for each storm.

In terms of LOE, our increase in per unit cost for the third quarter doesn’t tell the whole story. The cost per unit increase for the quarter is a direct result of the lower production in the quarter from hurricanes. Remember when we have a hurricane our LOE doesn’t stop when we are shut in or evacuate. We choose to pay our employees during this time. In fact direct operating expense (which we break out in our numbers) is 10% lower or $4.7 MM than last year. This was offset by a $6.7 MM increase in taxes and hurricane repairs and workovers. Outside the GOM, our direct operating expenses remained fairly flat except for the $1 MM fuel cost adjustment for our electric powered oil fields onshore. Our Remainco costs remained flat, Canada in fact, reduced costs from a year ago. Remainco is more oily, we still need to work on our $1.75/Mcfe operating costs next year as the higher Alaska non-operated costs play a bigger role.

On the Capital side, we’ve spent $343 MM YTD, pretty much on track with our budget but the $150 MM for the quarter reflects the ramp up of activity on Remainco properties in Western and Canada and some service cost increases.

Our slight increased guidance in capex reflects this ramp up and $7 MM in additional drilling costs during the hurricanes. We drilled 144 wells YTD, completing 137 producers for a 95% success rate. We have a large number of wells in progress at the end of the 3^rd quarter plus a large number of wells in Canada, around 15 wells, to tie-in.

We’ve seen quite an increase in drilling dayrates this year, as much as 40% since the beginning of the year. We’ve mitigated the bulk of these price increases as exhibited by the fact that we’ve been close to the capital budget we poured almost a year ago.

We did this by gains in drilling efficiencies through technique improvements in our multi-well plays and by using our own drilling fleet. We have also signed some one and two year contracts with contractors in our multi-well programs in the U.S. and Canada. We’ve had fewer problems procuring services in Alaska and Canada as opposed to the lower 48 states.

Our increased DD&A rate in the 3^rd quarter simply reflects our new estimates for future costs based on recent price increases. We would hope to bring these down at year end and next year as we add new reserves and spend more money on lower F&D cost plays onshore. Remember our Buffalo Wallow program, for example, will drill up the original PUD locations this year so new reserves will be added in the future. Now for the operations highlights.

WESTERN BUSINESS UNIT

Buffalo Wallow continues to move along as projected. During the 3^rd qtr, we completed 14 wells, bringing our total to 25 wells year-to-date, all at 100%

success. We have 7 wells in progress. Initial rates continue to be higher than the original forecast with recent wells having an average IP of 2.7 MMcfe/d, which is the best average to date. This can be attributed to more frac stages and we now drill to the deeper Atoka zone as standard practice. Net production is at 32 MMcfe/d, which is 10% higher than last quarter and 60% higher than the rate we initially had at closing. We still run a 4 drilling rig program, our 5^th rig has been doing the additional work in the Haley Atoka play of West Texas, so we have another rig contracted to start in Buffalo Wallow in the first quarter of 2006. We have already drilled most of our PUD locations, and we’ve got over 300 locations remaining to drill.

Another highlight for our company this quarter is our first test in the greater Haley/Vermejo area was a success. It came on after frac at 5 MMcfe/d and we have 100% WI in this well. This was a cheap re-entry of an old well which cost only $2-3 MM so these are excellent economics compared to deep drilling. The next two drilling wells should be down this quarter. Based on this success, we’ve added to this program in terms of activity for 2005 and acreage. Our net acreage is up to 30,000 acres and we will add 2 more re-entries/deepenings by year end. Even though there have been some isolated dramatic rates reported by other operators in this field, we hoped for 3-5 MMcfe/d wells on average, so we’re pleased with the first test. The early success in this area is one reason why our Rig #8 has been delayed getting to Buffalo Wallow.

Also during the 3^rd quarter, we added 6,400 acres in SE New Mexico for our Morrow play. We started with 6-10% WI in the area we got in a large

acquisition, but our Western Business folks have built our position to the point that we will have 50% WI in some of the new wells. These wells have solid economics and have averaged 1.9 MM/D initial rate.

In the Central Midland Basin in West Texas we’ve drilled 21 wells year-to-date and we’ve now identified 150 potential infill locations. In Andrews County, we’re now seeing operators go from 20 to 10 acre spacing and we’ve yet to get to 20 acres on the fields we acquired in late 2004. These wells are fairly shallow and we’re using our own drilling rigs here. Production rates on the oil wells range between 45 to 360 BOPD.

CANADA BUSINESS UNIT

In Canada we resumed our active drilling program in Central Alberta with the focus being in and around Wild River area. We also have initiated a shallow gas and oil drilling program starting in the fourth quarter.

We set another production record in Wild River during the 3^rd quarter with gross production reading 49 MMcfe/d. This is a 36% increase since last quarter. A total of 26 wells have been drilled to date at 100% success rate. We have 160 acre spacing approved but we have approximately 100 potential locations yet to drill. The organic growth for the 4^th quarter from Canada will come from tying in the new wells.

I should touch a minute on our new shallow program in Canada. We’ve recently drilled 3 shallow gas wells at Kaybob with tests averaging 1.5 MM/D and they’re 4,000-6,000’ deep. We will initiate a shallow program at Kaybob, Rimbey

and Evi-loon which involves mainly infill and step out drilling which could potentially involve over 100 locations.

The greater Wild River area, Shallow Plains and Foothills will be the core of our active Canadian program. We’ve got a lot of acreage up there.

SOUTHERN BUSINESS UNIT

We completed our fifth exploration well on our 150,000 acre Sabine prospect in SW Louisiana. Although the 185 BOPD rate was lower than the previous average, we are now 5 of 5 in finding hydrocarbons. The sixth well is drilling currently. We will acquire additional 3-D seismic in early 2006.

The new Southern Business unit will be focused on SW Louisiana, South Texas and East Texas plays with heavy emphasis on Frio, Yegua, Wilcox and Vicksburg targets.

GULF OF MEXICO

We continue to operate business as usual on our offshore GOM operations to insure a smooth transition to Mariner early next year. The wells mentioned in the press release were 2^nd quarter wells which were delayed in hook-up due to storms and equipment availability. The rates are better than anticipated from each project and add 20-30 MM/D of incremental production. We will spud our next deep shelf wells at SS 26 and ST 288 in the 4^th quarter. So we got good momentum going into the Mariner transaction for 2006 in addition to being ahead of the third parties on our hurricane repairs.

ALASKA BUSINESS UNIT

Our Alaska gas exploration is doing well. First, we initiated new gas sales in November. Our current net sales is 8 MM/D and will go higher as we ramp up the rate from the new wells.

We have 3 wells in progress at this time in onshore Cook Inlet. One is a delineation well at our TMC discovery and 2 are next West Foreland. We could have as many as 5 additional wells reached TD by the end of the year including these 3 in progress. We also added approximately 9,000 acres around one of these prospects at a recent lease sale.

So in summary, we’ve now got a Remainco prospect inventory which includes over 2,000 projects which are heavily concentrated in the following fields, in no particular order these fields are:

Buffalo Wallow

Wild River

Kaybob

Evi-loon

Haley/Vermejo

Central Permian downspacing

Alaska gas

This gives us an inventory which should last for years to come as well as our favorable acreage position and gives me confidence in Remainco’s stated 10% organic growth guidance for 2006.

707 17th STREET, SUITE 3600

DIRECTOR - INVESTOR RELATIONS

707 17^th STREET, SUITE 3600