Fourth Quarter 2011 Net Sales Volumes of 342 MMcfe/d; 6% Sequential Organic Growth

Fourth Quarter 2011 Liquids Net Sales Volumes of 17.3 MBbls/d; 20% Sequential Organic Growth

Completed Five Horizontal Granite Wash Wells with an Average 24-Hour Initial Production Rate of 14.0 MMcfe/d (52% Liquids)

Completed Two Horizontal Missourian Wash Wells with an Average 24-Hour Initial Production Rate of 3,765 Boe/d (72% Oil, 87% Liquids)

Completed Two Horizontal Eagle Ford Shale Wells in the Uppermost Member with an Average 24-Hour Production Rate of 604 Boe/d (98% Oil)

Completed Two Horizontal Liquids-Rich Cotton Valley Wells with an Average 24-Hour Initial Production Rate of 8.0 MMcfe/d (34% Liquids)

Added 236,900 Gross Acres (195,500 Net) in Highly Prospective Oil and Liquids-Rich Areas in 2011

2011 Drill Bit Reserve Replacement of 247% with Finding and Development Costs of $2.27 per Mcfe

2011 All-Sources Reserve Replacement of 148% with Finding and Development Costs of $3.77 per Mcfe

DENVER--(BUSINESS WIRE)--February 21, 2012--Forest Oil Corporation (NYSE:FST) (Forest or the Company) today announced financial and operational results for the fourth quarter and full-year 2011 and provided year-end estimated proved reserves. The financial results of Forest's former Canadian subsidiary, Lone Pine Resources Inc. (Lone Pine) (NYSE: LPR) (TSX: LPR), are treated as discontinued operations in the accompanying full-year consolidated financial statements.

The information contained throughout the remainder of this press release, unless otherwise indicated, relates only to the retained operations of Forest and excludes the operations of Lone Pine from the current and historic periods.

Forest reported the following highlights for the three months ended December 31, 2011:

H. Craig Clark, President and CEO, stated, "2011 was a transitional year for Forest through the advancement of numerous oil drilling opportunities in our U.S. asset portfolio following the Lone Pine transaction. We tested new shallow oil zones in the Texas Panhandle during 2011, including the Missourian Wash and the Cleveland formations which have attractive economics. Additionally, we are currently testing two other oil zones in the Panhandle area that, given early results and offset activity, show promise. Our advancement of oil development in the Texas Panhandle is complementary to our legacy horizontal drilling results in the Granite Wash where we have expanded the liquids-rich productive intervals to include the Granite Wash "A" and "C", and have now tested 11 intervals in the Texas Panhandle. While we have always recognized the enormous potential associated with the multitude of pay zones in the Texas Panhandle, the number of zones added during the year, and the quality of those zones, exceeded our initial expectations.

"In addition to the Texas Panhandle, Forest's operations included drilling highly productive areas of the Cotton Valley in East Texas that averaged 455 Bbls/d of oil and natural gas liquids, or 34% of the total equivalent initial production rate. Both the productivity and liquids content have exceeded that of our previous horizontal drilling programs in the Cotton Valley as a result of the geographic areas of focus and the implementation of improved completion technology. Forest's activity in East Texas will continue to focus on these areas throughout 2012.

"In our newer areas, through the utilization of advanced drilling and completion technologies and grass-roots leasing efforts, we were able to increase the size of our prospective liquids inventory. Specifically, our Eagle Ford Shale and Permian Basin programs have progressed significantly in 2011. During 2011 and early 2012, we were able to add 114,500 net acres in the Permian Basin, providing Forest access to potential oil resources in multiple oil-bearing pay zones that include the Wolfbone and Wolfcamp Shale plays.

"Forest's evolution in 2011 and into 2012 is designed to create a diverse set of drilling opportunities including oil, natural gas liquids, and natural gas, with prospects that can be drilled in diverse commodity price environments. We now have the acreage positions we feel can allow for large-scale development of a growing inventory, specifically a growing oil story.”

For the three months ended December 31, 2011, Forest reported net earnings from continuing operations of $19 million, or $0.17 per diluted share. This compares to Forest's net earnings from continuing operations of $6 million, or $0.05 per diluted share, in the corresponding 2010 period. Net earnings from continuing operations for the three months ended December 31, 2011 were affected by the following item:

Without the effect of this item, Forest's adjusted net earnings for the three months ended December 31, 2011 decreased 57% and 56% to $20 million, or $0.18 per diluted share, respectively, compared to $47 million, or $0.41 per diluted share in the corresponding 2010 period. Forest's adjusted EBITDA for the three months ended December 31, 2011 decreased 18% to $139 million compared to $169 million in the corresponding 2010 period. Forest's adjusted discretionary cash flow for the three months ended December 31, 2011 decreased 23% to $104 million compared to $135 million in the corresponding 2010 period.

The decrease in net earnings, EBITDA, and discretionary cash flow, each as adjusted, was primarily due to lower natural gas and natural gas liquids sales volumes and lower realized natural gas prices, partially offset by higher oil sales volumes and oil prices for the three months ended December 31, 2011, compared to the corresponding 2010 period.

Forest's net sales volumes for the three months ended December 31, 2011 decreased 12% to 342 MMcfe/d compared to the corresponding 2010 period. Sequentially, Forest's net sales volumes for the three months ended December 31, 2011 organically increased 6% compared to the three months ended September 30, 2011, including a 20% increase in oil and natural gas liquids production over the same period. Forest’s net sales volumes were comprised of 30% oil and natural gas liquids for the three months ended December 31, 2011 compared to 27% in the previous quarter. The following table details the components of net sales volumes, average realized prices, and revenues for the three months ended December 31, 2011:

	Three Months Ended December 31, 2011
	Gas		Oil			NGLs			Total
	(MMcf/d)		(MBbls/d)			(MBbls/d)			(MMcfe/d)

Net Sales Volumes		238.0		8.1			9.2			341.6

	Gas		Oil			NGLs			Total
Average Realized Prices	($/Mcf)		($/Bbl)			($/Bbl)			($/Mcfe)

Average realized prices not including realized derivative gains and losses	$	3.19	$	97.59		$	40.59		$	5.62
Realized gains (losses) on NYMEX derivatives		1.22		(3.66	)		(9.34	)		0.51
Average realized prices including realized derivative gains and losses	$	4.41	$	93.93		$	31.25		$	6.13

Revenues (in thousands)	Gas		Oil			NGLs			Total

Revenues not including realized derivative gains and losses	$	69,810	$	72,506		$	34,300		$	176,616
Realized gains (losses) on NYMEX derivatives		26,665		(2,717	)		(7,891	)		16,057
Revenues including realized derivative gains and losses	$	96,475	$	69,789		$	26,409		$	192,673

Forest's total cash costs for the three months ended December 31, 2011 increased 10% to $89 million compared to $81 million in the corresponding 2010 period. Total cash costs per-unit for the three months ended December 31, 2011 increased 25% to $2.83 per Mcfe compared to $2.26 per Mcfe in the corresponding 2010 period. The increase in total cash costs and total cash costs per-unit for the three months ended December 31, 2011 was primarily the result of additional water disposal costs associated with oil production in the Texas Panhandle and the Eagle Ford Shale, as well as decreased net sales volumes. The Company plans to lower its future disposal costs by drilling additional water disposal wells in 2012.

The following table details the components of total cash costs for the three months ended December 31, 2011 and 2010:

Total cash costs is a non-GAAP measure that is used by management to assess the Company’s cash operating performance. Forest defines total cash costs as all cash operating costs, including production expense; general and administrative expense (excluding stock-based compensation); interest expense; and current income tax expense.

Forest's per-unit depreciation and depletion expense for the three months ended December 31, 2011 increased 36% to $2.05 per Mcfe compared to $1.51 per Mcfe in the corresponding 2010 period. The increase was primarily the result of higher finding and development costs associated with Forest's oil and liquids-focused capital expenditure program.

Forest's exploration and development capital expenditures for the three months and year ended December 31, 2011 were $178 million and $683 million, respectively, compared to $95 million and $493 million in the corresponding 2010 periods. The increase in exploration and development capital expenditures was a result of increased oil and liquids-focused drilling in 2011 compared to the corresponding 2010 periods.

Forest’s land and leasehold acquisitions for the three months and year ended December 31, 2011 were $22 million and $205 million, respectively, compared to $3 million and $65 million in the corresponding 2010 periods. The increase in land and leasehold acquisitions was a result of Forest's strategic decision to expand exposure to prospective oil and liquids-rich areas. The addition of 38,300 gross acres (27,600 net) and 236,900 gross acres (195,500 net) in the Permian Basin, Eagle Ford Shale, Texas Panhandle, and other prospective liquids areas during the three months and year ended December 31, 2011, respectively, bolstered Forest's inventory of potential liquids drilling locations. The following table summarizes total capital expenditures incurred for the three months and year ended December 31, 2011 (in thousands):

Forest reported December 31, 2011 estimated proved reserves of 1,904 Bcfe, which were 55% proved developed, compared to 1,868 Bcfe at December 31, 2010, which were 61% proved developed. The increase in estimated proved reserves was driven by drilling programs in our core areas that included extensions and discoveries of 301 Bcfe, which were partially offset by 120 Bcfe of revisions. With continued focus on oil and liquids-rich drilling, extensions and discoveries were comprised of 52% oil and natural gas liquids and 48% natural gas. The amount of estimated proved reserves comprised of oil and natural gas liquids at year-end 2011 increased to 24% as compared to 20% at year end 2010. The pricing utilized for estimated proved reserves at December 31, 2011 was based on a 12-month average of the 2011 first-day-of-the-month Henry Hub price for natural gas and West Texas Intermediate price for oil of $4.12 per MMbtu and $96.08 per barrel, respectively. This compares to the pricing utilized for estimated proved reserves at December 31, 2010 for natural gas and oil of $4.38 per MMbtu and $79.81 per barrel, respectively. Forest's estimated proved reserves were audited by DeGolyer and MacNaughton (D&M), an independent third party engineering firm. D&M's audit covered properties representing over 83% of the value of Forest's total estimated proved reserves at year end 2011.

The following table reflects the 2011 activity related to the estimated proved reserves and includes calculations of reserve replacement ratios and finding and development costs utilizing net sales volumes and capital expenditures:


	Estimated Proved Reserves (Bcfe)

December 31, 2010		1,868

Extensions and discoveries		301
Reserve additions		301

Net sales volumes		(122	)
Sales of properties		(23	)
Five year PUD limitation revision ^(A)		(47	)
South Louisiana exploration revision ^(B)		(23	)
Other revisions		(50	)
Reserve subtractions		(265	)

December 31, 2011		1,904

Drill bit reserve replacement ratio excluding revisions ⁽¹⁾		247	%

Drill bit finding and development costs excluding revisions (per Mcfe) ⁽²⁾	$	2.27

All-sources reserve replacement ratio ⁽³⁾		148	%

All-sources finding and development costs (per Mcfe) ⁽⁴⁾	$	3.77

Reserve : production ratio (years)		15.6

EXPLANATION OF REVISIONS, RESERVE REPLACEMENT RATIO, AND
FINDING AND DEVELOPMENT COSTS

The following discussion relates to Forest's reserve replacement ratios and finding and development costs in 2011:

	⁽¹⁾		The drill bit reserve replacement ratio excluding revisions of 247% was calculated by dividing extensions and discoveries of 301 Bcfe by net sales volumes of 122 Bcfe.

	⁽²⁾		The drill bit finding and development costs excluding revisions of $2.27 per Mcfe was calculated by dividing the sum of exploration and development capital expenditures (excluding land and leasehold acquisitions, asset retirement obligations, capitalized interest, and capitalized equity compensation) of $683 million by extensions and discoveries of 301 Bcfe.

	⁽³⁾		The all-sources reserve replacement ratio of 148% was calculated by dividing the difference of extensions and discoveries of 301 Bcfe and revisions of 120 Bcfe by net sales volumes of 122 Bcfe.

	⁽⁴⁾		The all-sources finding and development costs of $3.77 per Mcfe was calculated by dividing the sum of exploration and development capital expenditures (excluding land and leasehold acquisitions, asset retirement obligations, capitalized interest, and capitalized equity compensation) of $683 million by the difference of extensions and discoveries of 301 Bcfe and revisions of 120 Bcfe.

Forest holds approximately 180,000 gross acres (109,000 net) in the Texas Panhandle. The area provides horizontal drilling opportunities targeting multiple liquids-rich Granite Wash intervals as well as other multi-pay objectives, including uphole oil zones. During 2011, Forest tested six prospective intervals in the Texas Panhandle, establishing a total of eleven intervals as currently commercial for horizontal development. In addition to these horizontal zones within the Texas Panhandle, Forest has identified an additional five intervals as prospective for horizontal development.

Since Forest's last earnings release, the Company has completed five horizontal Granite Wash wells (72% working interest) that had an average 24-hour initial production rate of 14.0 MMcfe/d, including approximately 1,200 Bbls/d of liquids or 52% of total equivalent production. Three of these wells, completed in the Granite Wash “A” zone, had average 24-hour initial production rates of 16.8 MMcfe/d with a liquids content of approximately 50%.

Forest has also had continued success in the Missourian Wash interval. Since Forest's last earnings release, the Company has completed two additional Missourian Wash wells (69% working interest) that had an average 24-hour initial production rate of 2,721 Bbls/d of oil, 546 Bbls/d of NGLs, and 3.0 MMcf/d of natural gas, for a total equivalent rate of 3,765 Boe/d.

In addition to the success achieved in the Missourian Wash and Cleveland oil zones, a new oil zone (80% working interest) located outside of Wheeler and Hemphill Counties, yielded a 24-hour initial production rate of 821 Bbls/d of oil, 492 Bbls/d of NGLs, and 4.3 MMcf/d of natural gas, for a total equivalent rate of 12.2 MMcfe/d.

The Company experienced production downtime in the Texas Panhandle in the fourth quarter for compression and plant downtime, which resulted in a reduction of net sales volumes of approximately 4 MMcfe/d in the quarter. In order to reduce third party pipeline and plant issues of the type encountered during 2011, Forest has installed loop lines, compression, and selected a new primary gas gatherer for its production in this area. It is anticipated that production will be moved to the new primary gas gatherer in increments over the next year.

Forest holds approximately 112,000 gross acres (103,000 net) in the Eagle Ford Shale play. The reduction from 128,000 gross acres (118,000 net) is a result of allowing non held-by-production acreage in Lee County to expire, but Forest's core acreage position in Gonzales and Wilson Counties of 101,000 gross acres (93,000 net) has been maintained. The area provides Forest access to the oil-bearing section of the Eagle Ford and has the potential to become a significant oil development opportunity through the application of advanced horizontal drilling and completion technologies.

Since Forest's last earnings release, Forest successfully completed three horizontal Eagle Ford Shale oil wells (100% working interest) that had an average 24-hour production rate of 532 Boe/d. Two of these wells, drilled in the upper Eagle Ford, had an average 24-hour production rate of 604 Boe/d. A fourth well, also drilled in the upper Eagle Ford, experienced an unsuccessful completion due to a poor cement job. Remedial work is being performed to accomplish a successful completion of this well.

Forest holds approximately 168,000 gross acres (125,000 net) in the East Texas / North Louisiana area. The area provides horizontal drilling opportunities targeting multi-pay natural gas and oil and natural gas liquids intervals.

Since Forest's last earnings release, Forest completed two horizontal Cotton Valley wells (100% working interest) in East Texas that had an average 24-hour initial production rate of 8.0 MMcfe/d, including 455 Bbls/d of oil and natural gas liquids.

Additionally, Forest completed two wells in its Red River Parish acreage (100% working interest) that had an average initial restricted rate of approximately 10.5 MMcf/d with flowing pressures averaging 8,431 psi. These wells have averaged 9.4 MMcf/d over their combined 111 producing days. These two wells utilized Forest’s newly built pad drilling equipment as an incremental cost saving initiative.

As of February 21, 2012, Forest had natural gas, natural gas liquids, and oil derivatives in place for 2012 and 2013 covering the aggregate average daily volumes and weighted average prices shown below:

	⁽¹⁾		During the fourth quarter of 2011, Forest entered into derivative agreements for the period from April 2012 to December 2012 subjecting 50 Bbtu/d of the 2012 gas swaps to a written put of $3.53 and a $4.00-to-$4.50 call spread whereby Forest receives $5.30 except as follows: Forest receives (i) NYMEX Henry Hub (HH) plus $1.77 when NYMEX HH is below $3.53; (ii) $5.30 plus the value of the call spread when NYMEX HH is between $4.00 and $4.50; and (iii) $5.80 when NYMEX HH is $4.50 or above.

			In connection with entering into certain 2012 gas swaps with premium hedged prices, Forest granted oil puts to the counterparties, giving the counterparties the option to put 5 MBbls/d to Forest at $75.00 per Bbl on a monthly basis during the April 2012 to December 2012 period.

In connection with several swaps shown in the table above, Forest granted option instruments to counterparties in exchange for Forest receiving premium hedged prices on the swaps. The table below sets forth the outstanding options as of February 21, 2012:

In addition to reporting net earnings from continuing operations as defined under generally accepted accounting principles (GAAP), Forest also presents adjusted net earnings from continuing operations (adjusted net earnings), which is a non-GAAP performance measure. Adjusted net earnings consists of net earnings from continuing operations after adjustment for those items shown in the table below. Adjusted net earnings does not represent, and should not be considered an alternative to, GAAP measurements such as net earnings from continuing operations (its most comparable GAAP financial measure), and Forest's calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items shown below, Forest believes that the measure is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in the oil and gas industry. Forest's management does not view adjusted net earnings in isolation and also uses other measurements, such as net earnings from continuing operations and revenues to measure operating performance. The following table provides a reconciliation of net earnings from continuing operations, the most directly comparable GAAP measure, to adjusted net earnings for the periods presented (in thousands):

	Three Months Ended December 31,						Year Ended December 31,
	2011			2010			2011			2010

Net earnings from continuing operations	$	19,467		$	5,896		$	98,260		$	189,662

Unrealized losses (gains) on derivative instruments, net of tax		940			41,474			(24,957	)		(24,300	)
Gain on debt extinguishment, net of tax		-			-			-			(2,921	)
Legal proceeding settlement, net of tax		-			-			4,149			-
Canadian dividend tax, net of tax		-			-			18,460			-
Spin-off stock compensation expense, net of tax		-			-			4,228			-
Adjusted net earnings	$	20,407		$	47,370		$	100,140		$	162,441

Earnings attributable to participating securities and other adjustments		(444	)		(964	)		(2,076	)		(3,200	)
Adjusted net earnings for diluted earnings per share	$	19,963		$	46,406		$	98,064		$	159,241

Weighted average number of diluted shares outstanding		112,382			112,012			112,868			111,498

Adjusted diluted earnings per diluted share	$	0.18		$	0.41		$	0.87		$	1.43

In addition to reporting net earnings from continuing operations as defined under GAAP, Forest also presents adjusted net earnings before interest, income taxes, depreciation, depletion, and amortization from continuing operations (adjusted EBITDA), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings from continuing operations after adjustment for those items shown in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to, GAAP measurements such as net earnings from continuing operations (its most comparable GAAP financial measure), and Forest's calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items shown below, Forest believes the measure is useful in evaluating its fundamental core operating performance. Forest also believes that adjusted EBITDA is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in the oil and gas industry. Forest's management uses adjusted EBITDA to manage its business, including in preparing its annual operating budget and financial projections. Forest's management does not view adjusted EBITDA in isolation and also uses other measurements, such as net earnings from continuing operations and revenues to measure operating performance. The following table provides a reconciliation of net earnings from continuing operations, the most directly comparable GAAP measure, to adjusted EBITDA for the periods presented (in thousands):

	Three Months Ended December 31,				Year Ended December 31,
	2011		2010		2011			2010

Net earnings from continuing operations	$	19,467	$	5,896	$	98,260		$	189,662

Income tax expense		12,195		532		89,135			109,770
Unrealized losses (gains) on derivative instruments, net		1,451		64,919		(39,087	)		(37,920	)
Legal proceeding settlement		-		-		6,500			-
Interest expense		36,674		37,397		149,755			149,891
Gain on debt extinguishment, net		-		-		-			(4,576	)
Accretion of asset retirement obligations		1,586		1,491		6,082			6,158
Depreciation, depletion, and amortization		64,457		53,994		219,684			187,973
Stock-based compensation		2,727		4,578		20,536			18,143

Adjusted EBITDA	$	138,557	$	168,807	$	550,865		$	619,101

In addition to reporting net cash provided by operating activities of continuing operations as defined under GAAP, Forest also presents adjusted discretionary cash flow of continuing operations (adjusted discretionary cash flow), which is a non-GAAP liquidity measure. Adjusted discretionary cash flow consists of net cash provided by operating activities of continuing operations after adjustment for those items shown in the table below. This measure does not represent, and should not be considered an alternative to, GAAP measurements such as net cash provided by operating activities of continuing operations (its most comparable GAAP financial measure), and Forest's calculations thereof may not be comparable to similarly titled measures reported by other companies. Forest's management uses adjusted discretionary cash flow as a measure of liquidity and believes it provides useful information to investors because it assesses cash flow from operations before changes in operating assets and liabilities, which fluctuates due to the timing of collections of receivables and the settlements of liabilities, and other items. Forest's management uses adjusted discretionary cash flow to manage its business, including in preparing its annual operating budget and financial projections. This measure does not represent the residual cash flow available for discretionary expenditures. Forest’s management does not view adjusted discretionary cash flow in isolation and also uses other measurements, such as net cash provided by operating activities of continuing operations to measure operating performance. The following table provides a reconciliation of net cash provided by operating activities of continuing operations, the most directly comparable GAAP measure, to adjusted discretionary cash flow for the periods presented (in thousands):

	Three Months Ended December 31,						Year Ended December 31,
	2011			2010			2011			2010

Net cash provided by operating activities of continuing operations	$	92,683		$	114,026		$	398,097		$	446,725

Changes in operating assets and liabilities:
Accounts receivable		6,450			21,094			(23,236	)		(2,640	)
Other current assets		(6,052	)		(13,660	)		(14,314	)		(24,136	)
Accounts payable and accrued liabilities		1,374			521			6,470			62,435
Accrued interest and other current liabilities		9,543			12,900			5,566			7,766
Canadian dividend tax ⁽¹⁾		-			-			28,921			-
Legal proceeding settlement ⁽¹⁾		-			-			6,500			-
Current income taxes associated with oil and gas property divestitures		-			-			-			(16,984	)

Adjusted discretionary cash flow	$	103,998		$	134,881		$	408,004		$	473,166

In addition to reporting total debt as defined under GAAP, Forest also presents net debt, which is a non-GAAP debt measure. Net debt consists of the principal amount of debt adjusted for cash and cash equivalents at the end of the period. Forest's management uses net debt to assess Forest's indebtedness. The following table sets forth the components of net debt (in thousands):

A conference call is scheduled for Wednesday, February 22, 2012, at 12:00 PM MT to discuss the release. You may access the call by dialing toll free 866.700.0161 (for U.S./Canada) and 617.213.8832 (for International) and request the Forest Oil teleconference (ID # 72849675). The conference call will also be webcast live on the Internet and can be accessed by going to the Forest Oil website at www.forestoil.com in the "Investor Relations" section of the website. A Q&A period will follow.

A replay will be available from Wednesday, February 22 through March 7, 2012. You may access the replay by dialing toll free 888.286.8010 (for U.S./Canada) and 617.801.6888 (for International), conference ID # 73756132. An archive of the conference call webcast will also be available at www.forestoil.com in the "Investor Relations" section of the website.

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 future natural gas and liquids production, revenues, cash flows, liquidity, plans for future operations, expenses, outlook for oil and natural gas prices, timing of capital expenditures, and other forward-looking statements relating to Forest are subject to all of the risks and uncertainties normally incident to their exploration for and development and production and sale of oil and gas.

These risks relating to Forest include, but are not limited to, oil and natural gas price volatility, its access to cash flows and other sources of liquidity to fund its capital expenditures, its level of indebtedness, its ability to replace production, the impact of the current financial and economic environment on its business and financial condition, a lack of availability of, or increase in costs relating to, 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 reports that Forest files with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K. 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 the United States and selected international locations. Forest's principal reserves and producing properties are located in the United States in Arkansas, Louisiana, Oklahoma, Texas, Utah, and Wyoming. 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.


FOREST OIL CORPORATION Condensed Consolidated Balance Sheets (Unaudited)

	December 31,
	2011			2010
ASSETS	(In thousands)

Current assets:
Cash and cash equivalents	$	3,012		$	217,569
Accounts receivable		79,089			102,325
Derivative instruments		89,621			60,182
Other current assets		38,950			51,465
Current assets of discontinued operations		-			50,142
Total current assets		210,672			481,683

Net property and equipment		2,651,116			2,070,273

Deferred income taxes		231,116			284,021
Goodwill		239,420			239,420
Derivative instruments		10,422			8,244
Other assets		38,405			36,698
Long-term assets of discontinued operations		-			665,049
	$	3,381,151		$	3,785,388

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	247,880		$	209,998
Accrued interest		23,259			23,630
Derivative instruments		28,944			36,413
Deferred income taxes		20,172			6,911
Current portion of long-term debt		-			287,092
Other current liabilities		20,582			19,683
Current liabilities of discontinued operations		-			45,647
Total current liabilities		340,837			629,374

Long-term debt		1,693,044			1,582,280
Asset retirement obligations		77,898			73,011
Other liabilities		76,259			73,463
Long-term liabilities of discontinued operations		-			74,473
Total liabilities		2,188,038			2,432,601

Shareholders' equity:
Common stock		11,454			11,359
Capital surplus		2,486,994			2,684,269
Accumulated deficit		(1,287,063	)		(1,424,905	)
Accumulated other comprehensive (loss) income		(18,272	)		82,064

Total shareholders' equity		1,193,113			1,352,787

	$	3,381,151		$	3,785,388

FOREST OIL CORPORATION Condensed Consolidated Statements of Operations (Unaudited)

	Three Months Ended					Year Ended
	December 31,					December 31,
	2011			2010		2011			2010
	(In thousands, except per share amounts)

Revenues:
Oil, gas, and NGL sales	$	176,616		$	178,680	$	703,531		$	707,692
Interest and other		87			518		1,026			989
Total revenues		176,703			179,198		704,557			708,681

Costs, expenses, and other:
Lease operating expenses		28,565			22,845		99,158			92,394
Production and property taxes		8,445			8,237		40,632			43,656
Transportation and processing costs		3,465			4,014		13,728			13,242
General and administrative expense		15,983			15,870		65,105			64,886
Depreciation, depletion, and amortization		64,457			53,994		219,684			187,973
Interest expense		36,674			37,397		149,755			149,891
Realized and unrealized (gains) losses on derivative instruments, net		(17,432	)		27,266		(88,064	)		(150,132	)
Other, net		4,884			3,147		17,164			7,339
Total costs, expenses, and other		145,041			172,770		517,162			409,249
Earnings from continuing operations before income taxes		31,662			6,428		187,395			299,432
Income tax		12,195			532		89,135			109,770
Net earnings from continuing operations		19,467			5,896		98,260			189,662
Net earnings from discontinued operations		-			10,298		44,569			37,859
Net earnings		19,467			16,194		142,829			227,521
Less: net earnings attributable to noncontrolling interest		-			-		4,987			-
Net earnings attributable to Forest Oil Corporation	$	19,467		$	16,194	$	137,842		$	227,521

Basic earnings per common share attributable to Forest Oil Corporation common shareholders:
Earnings from continuing operations	$	0.17		$	0.05	$	0.86		$	1.68
Earnings from discontinued operations		-			0.09		0.35			0.33
Basic earnings per common share attributable to Forest Oil Corporation common shareholders	$	0.17		$	0.14	$	1.21		$	2.01

Diluted earnings per common share attributable to Forest Oil Corporation common shareholders:
Earnings from continuing operations	$	0.17		$	0.05	$	0.85		$	1.67
Earnings from discontinued operations		-			0.09		0.34			0.33
Diluted earnings per common share attributable to Forest Oil Corporation common shareholders	$	0.17		$	0.14	$	1.19		$	2.00

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

	Three Months Ended						Year Ended
	December 31,						December 31,
	2011			2010			2011			2010
	(In thousands)
Operating activities:
Net earnings	$	19,467		$	16,194		$	142,829		$	227,521
Less: net earnings from discontinued operations		-			10,298			44,569			37,859
Net earnings from continuing operations		19,467			5,896			98,260			189,662

Adjustments to reconcile net earnings from continuing operations to net cash provided by operating activities of continuing operations:
Depreciation, depletion, and amortization		64,457			53,994			219,684			187,973
Deferred income tax		12,270			2,344			58,994			123,671
Unrealized losses (gains) on derivative instruments, net		1,451			64,919			(39,087	)		(37,920	)
Stock-based compensation		2,727			4,578			20,536			18,143
Accretion of asset retirement obligations		1,586			1,491			6,082			6,158
Other, net		2,040			1,659			8,114			2,463

Changes in operating assets and liabilities:
Accounts receivable		(6,450	)		(21,094	)		23,236			2,640
Other current assets		6,052			13,660			14,314			24,136
Accounts payable and accrued liabilities		(1,374	)		(521	)		(6,470	)		(62,435	)
Accrued interest and other current liabilities		(9,543	)		(12,900	)		(5,566	)		(7,766	)
Net cash provided by operating activities of continuing operations		92,683			114,026			398,097			446,725

Investing activities:
Capital expenditures for property and equipment:
Exploration, development, acquisition, and leasehold costs		(216,983	)		(117,301	)		(873,877	)		(556,988	)
Other fixed assets		(2,598	)		(1,421	)		(6,968	)		(5,143	)
Proceeds from sales of assets		159			10,489			121,115			139,077
Net cash used by investing activities of continuing operations		(219,422	)		(108,233	)		(759,730	)		(423,054	)

Financing activities:
Proceeds from bank borrowings		148,000			-			160,000			-
Repayments of bank borrowings		(43,000	)		-			(55,000	)		-
Redemption of senior notes		(285,000	)		-			(285,000	)		(152,038	)
Change in bank overdrafts		37,776			(7,334	)		17,116			6,378
Other, net		1,886			3,905			(10,421	)		3,449
Net cash used by financing activities of continuing operations		(140,338	)		(3,429	)		(173,305	)		(142,211	)

Cash flows of discontinued operations:
Operating cash flows		-			20,596			101,292			86,204
Investing cash flows		-			(58,058	)		(255,470	)		(218,155	)
Financing cash flows		-			1,585			478,324			1,692
Net cash (used) provided by discontinued operations		-			(35,877	)		324,146			(130,259	)
Effect of exchange rate changes on cash		-			59			(3,476	)		(277	)
Net decrease in cash and cash equivalents		(267,077	)		(33,454	)		(214,268	)		(249,076	)
Net decrease (increase) in cash and cash equivalents of discontinued operations		-			8,345			(289	)		8,370
Net decrease in cash and cash equivalents of continuing operations		(267,077	)		(25,109	)		(214,557	)		(240,706	)
Cash and cash equivalents of continuing operations at beginning of period		270,089			242,678			217,569			458,275
Cash and cash equivalents of continuing operations at end of period	$	3,012		$	217,569		$	3,012		$	217,569

CONTACT:
Forest Oil Corporation
Patrick J. Redmond, 303-812-1441
VP - Corporate Planning and Investor Relations

	Three Months Ended December 31,
	2011			Per Mcfe			2010			Per Mcfe
	(In thousands, except per-unit amounts)

Production expense	$	40,475		$	1.29		$	35,096		$	0.98
General and administrative expense (excluding stock-based compensation of $4,071 and $5,508, respectively)		11,912			0.38			10,362			0.29
Interest expense		36,674			1.17			37,397			1.04
Current income tax expense		(75	)		(0.00	)		(1,812	)		(0.05	)
Total cash costs	$	88,986		$	2.83		$	81,043		$	2.26

	Three Months Ended December 31,		Year Ended December 31,
	2011		2011

Exploration and development	$	178,270	$	682,967
Land and leasehold acquisitions		22,390		204,537
	$	200,660	$	887,504

Add:
ARO, capitalized interest, and capitalized equity compensation		5,629		28,254
Total capital expenditures	$	206,289	$	915,758

	Jan - Mar		Apr - Dec
	2012		2012			2013
Natural gas swaps:
Contract volumes (Bbtu/d)		105.0		155.0	⁽¹⁾		100.0
Weighted average price (per MMBtu)	$	5.30	$	4.63		$	4.02

Natural gas liquids swaps:
Contract volumes (MBbls/d)		2.0		2.0			-
Weighted average price (per Bbl)	$	45.22	$	45.22		$	-

Oil swaps:
Contract volumes (MBbls/d)		5.0		4.7			-
Weighted average price (per Bbl)	$	98.24	$	97.60		$	-

	July - Dec 2012		2013		2014
Natural gas swaptions:
Contract volumes (Bbtu/d)		-		40.0		-
Weighted average price (per MMBtu)	$	-	$	4.02	$	-

Oil swaptions:
Contract volumes (MBbls/d)		0.5		5.0		3.0
Weighted average price (per Bbl)	$	107.10	$	105.00	$	109.67

	December 31, 2011				December 31, 2010
	Principal		Book⁽¹⁾		Principal		Book⁽¹⁾
Credit facility	$	105,000	$	105,000	$	-	$	-
8% Senior notes due 2011		-		-		285,000		287,092
7% Senior subordinated notes due 2013		12		12		12		12
8 1/2% Senior notes due 2014		600,000		587,611		600,000		581,790
7 1/4% Senior notes due 2019		1,000,000		1,000,421		1,000,000		1,000,478
Total debt		1,705,012		1,693,044		1,885,012		1,869,372

Less: cash and cash equivalents		3,012		3,012		217,569		217,569

Net debt	$	1,702,000	$	1,690,032	$	1,667,443	$	1,651,803

	^(A)		The five year estimated proved undeveloped reserve limitation revision is related to vertical wells in Forest's East Texas acreage. While Forest's current development plan does not schedule these vertical wells to be drilled within five years from their initial booking date, we intend to eventually drill these prospects as horizontal wells.

	^(B)		The South Louisiana estimated proved undeveloped reserve exploration revision is related to an inland water deep prospect determined to be uneconomic.

	⁽¹⁾		The Canadian dividend tax and legal proceeding settlement are non-recurring cash-settled items. Including the effect of these items, adjusted discretionary cash flow would have been $373 million for the year ended December 31, 2011.

	⁽¹⁾		Book amounts include the principal amount of debt adjusted for unamortized gains on interest rate swap terminations of $1 million at December 31, 2010 and unamortized net discounts on the issuance of certain senior notes of $(12) million and $(16) million at December 31, 2011 and 2010, respectively.