Fourth Quarter 2013 Average Net Sales Volumes of 165 MMcfe/d (62% Natural Gas, 38% Liquids)

Fourth Quarter 2013 Average Net Sales Volumes of 111 MMcfe/d (68% Natural Gas, 32% Liquids) Pro Forma for Divestitures

2013 Average Oil Net Sales Volumes Increase 55% Compared to 2012 Pro Forma for Divestitures

2013 Average Liquids Net Sales Volumes Increase 41% Compared to 2012 Pro Forma for Divestitures

2013 Estimated Proved Reserves of 625 Bcfe; Oil Reserves Increase 30% Compared to 2012 Pro Forma for Divestitures

2013 Drill Bit Reserve Replacement of 197% with Drill Bit Finding and Development Costs of $2.19 per Mcfe

DENVER--(BUSINESS WIRE)--February 25, 2014--Forest Oil Corporation (NYSE:FST) (Forest or the Company) today announced financial and operational results for the fourth quarter and full-year 2013 and provided year-end estimated proved reserves. References to pro forma results exclude asset sales completed during 2012 and 2013.

For the three months ended December 31, 2013, Forest reported net earnings of $106 million, or $0.89 per diluted share, compared to net earnings of $2 million, or $0.02 per share in the third quarter of 2013. Net earnings for the fourth quarter of 2013 included the following items:

Without the effect of these items, Forest’s results for the fourth quarter were as follows:

The decreases in net earnings, EBITDA, and discretionary cash flow, each on an adjusted basis, were primarily the result of the Texas Panhandle asset divestiture in the fourth quarter of 2013.

Forest's average net sales volumes for the three months ended December 31, 2013, were 165 MMcfe/d. Excluding volumes associated with the Texas Panhandle divestiture that closed on November 25, 2013, fourth quarter 2013 net sales volumes averaged 111 MMcfe/d. This compares to third quarter 2013 average net sales volumes of 114 MMcfe/d excluding asset sales.

During the fourth quarter, the company-wide differential for crude oil was $6.69 per Bbl less than the NYMEX West Texas Intermediate (WTI) price, compared to $2.88 per Bbl less than the WTI price in the third quarter of 2013. The decrease was primarily the result of a narrowing of the Light Louisiana Sweet (LLS) premium relative to WTI that the Company received for its oil production in the Eagle Ford and Ark-La-Tex areas.

The following table details the components of average net sales volumes, average realized prices, and revenues for the three months ended December 31, 2013:


	Three Months Ended December 31, 2013
	Gas		Oil			NGLs		Total
	(MMcf/d)		(MBbls/d)			(MBbls/d)		(MMcfe/d)

Average Net Sales Volumes		101.8		5.3			5.2		164.7


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

Average realized prices not including realized derivative gains (losses)	$	3.07	$	90.82		$	32.15	$	5.84
Realized gains (losses) on NYMEX derivatives		0.52		(0.65	)		-		0.30
Average realized prices including realized derivative gains (losses)	$	3.59	$	90.16		$	32.15	$	6.14

Revenues (in thousands)	Gas		Oil			NGLs		Total

Revenues not including realized derivative gains (losses)	$	28,745	$	44,500		$	15,240	$	88,485
Realized gains (losses) on NYMEX derivatives		4,884		(320	)		-		4,564
Revenues including realized derivative gains (losses)	$	33,629	$	44,180		$	15,240	$	93,049

The following table details the components of average net sales volumes for the fourth quarter of 2013 and full-year 2013 excluding asset divestitures:

Forest's total cash costs for the fourth quarter of 2013, excluding stock-based compensation and employee-related asset disposition costs, decreased 17% to $53 million, compared to $64 million in the third quarter of 2013. Total cash costs per-unit for the fourth quarter of 2013 increased 5% to $3.48 per Mcfe, compared to $3.31 per Mcfe in the third quarter of 2013, primarily as a result of lower equivalent production volumes and having a greater proportion of higher operating cost oil properties following the sale of the Texas Panhandle assets.

The following table details the components of total cash costs for the comparative periods:


	Three Months Ended
	December 31, 2013			Per Mcfe			September 30, 2013			Per Mcfe
	(In thousands, except per-unit amounts)
Production expense	$	22,731		$	1.50		$	26,702		$	1.39
General and administrative expense (excluding stock-based compensation and employee-related asset disposition costs of $6,485 and $1,784, respectively)		5,448			0.36			7,981			0.42
Interest expense		24,790			1.64			29,519			1.54
Current income tax benefit		(245	)		(0.02	)		(587	)		(0.03	)
Total cash costs	$	52,724		$	3.48		$	63,615		$	3.31

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 and employee-related asset disposition costs); interest expense; and current income tax expense.

Forest's exploration and development capital expenditures for the three months and the year-ended December 31, 2013, are set forth in the table below (in thousands):

Forest reported December 31, 2013 estimated proved reserves of 625 Bcfe, which were 66% proved developed, compared to 1,363 Bcfe at December 31, 2012, which were 69% proved developed. The decrease in estimated proved reserves was a result of 800 Bcfe of asset divestitures in 2013 partially offset by extensions and discoveries of 148 Bcfe. With continued focus on oil and liquids-rich drilling, extensions and discoveries were comprised of 66% oil and natural gas liquids and 34% natural gas. The pricing utilized for estimated proved reserves at December 31, 2013 was based on a 12-month average of the 2013 first-day-of-the-month Henry Hub price for natural gas and West Texas Intermediate price for oil of $3.67 per MMbtu and $97.33 per barrel, respectively. This compares to the pricing utilized for estimated proved reserves at December 31, 2012 for natural gas and oil of $2.76 per MMbtu and $94.79 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 87% of the value of Forest's total estimated proved reserves at year-end 2013.

The following table reflects the 2013 activity related to the estimated proved reserves and includes calculations of reserve replacement ratio and finding and development costs utilizing net sales volumes and capital expenditures:


	Estimated Proved Reserves (Bcfe)

December 31, 2012		1,363

Extensions and discoveries		148
Reserve additions		148

Net sales volumes		(75	)
Sales of properties		(800	)
Price-related revisions		40
Five year PUD limitation revision ⁽¹⁾		(41	)
Other revisions		(10	)
Reserve subtractions		(886	)

December 31, 2013		625

Drill bit reserve replacement ratio excluding revisions ⁽²⁾		197	%

Drill bit finding and development costs excluding revisions (per Mcfe) ⁽³⁾	$	2.19

Reserve : production ratio (years)⁽⁴⁾		8.3

⁽¹⁾		The five year estimated proved undeveloped reserve limitation revision is related primarily to natural gas assets located in the Ark-La-Tex.

⁽²⁾		The drill bit reserve replacement ratio excluding revisions of 197% was calculated by dividing extensions and discoveries of 148 Bcfe by net sales volumes of 75 Bcfe.

⁽³⁾		The drill bit finding and development costs, excluding revisions, of $2.19 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 $325 million by extensions and discoveries of 148 Bcfe.

⁽⁴⁾		The reserve to production ratio of 8.3 years was calculated by dividing proved reserves of 625 Bcfe by net sales volumes of 75 Bcfe.

Forest’s drilling and completion activity during 2013 was primarily focused on lease expirations in advance of transitioning to the development phase of the Eagle Ford program. The Company plans to hold through production a total of 49,000 gross (24,500 net) acres within Gonzales County, Texas.

For 2013, Forest reported results on 44 gross (22 net) wells that had a 30-day average gross production rate of 408 Boe/d (95% oil). This includes 17 gross (8.5 net) wells that were completed since the Company’s last operational update that had a 30-day average gross production rate of 304 Boe/d (94% oil), including seven gross (3.5 net) wells that were drilled as part of two separate well spacing and artificial lift pilot projects and three gross (1.5 net) wells that were drilled in areas where the completions were adversely impacted by faulting.

As is characteristic of field delineation efforts, initial production rates have varied as the Company focused on establishing and prioritizing its acreage position, gathering significant geologic and geophysical data, developing the optimal drilling, well completion, and fracture stimulation techniques, conducting well spacing tests, and identifying the most appropriate form of artificial lift. This data has provided a better understanding of the geologic and reservoir characteristics and attributes of the producing formation, which will be utilized during 2014 to determine well locations, assist in reducing costs, and enhance performance.

Well spacing tests were conducted in two areas of the field in the fourth quarter to determine optimal spacing for the parts of the field that have distinct reservoir and production characteristics. Based on drilling and completion results and initial production data from these two projects, Forest believes that an average lateral spacing of 500-feet to 1,000-feet between wells will be the development configuration for the majority of the acreage position.

Forest encountered greater-than-anticipated faulting in a portion of its southern acreage position that adversely impacted the flow rate of three wells. The fault complexes were located in an area where two of the Company’s seismic surveys overlap. Forest is in the process of merging and reprocessing its existing 3D seismic surveys so that it can more accurately identify and avoid fault complexes at the edge of the seismic surveys where the faulting was encountered. It is expected that the reprocessed data will be available and utilized to select drilling locations by the third quarter of 2014. Forest plans to focus its first half of 2014 drilling program in areas where it has a high degree of confidence in the geology, geophysical, and reservoir data and believes the fault patterns are accurately imaged. The southern area is considered to be the more productive part of the field and will be the primary focus of the 2014 drilling program.

While the seismic is being reprocessed and optimal well design is being evaluated, Forest has elected to reduce the pace of drilling in the Eagle Ford. As such, the 2014 drilling plan will entail drilling 48 gross (24 net) wells. Forest expects that the net capital allocated to the Eagle Ford for drilling and completion activities in 2014 will total $95 million.

Net sales volumes from the Eagle Ford averaged approximately 2,950 Boe/d in the fourth quarter of 2013. Drilling and completion costs averaged approximately $5.6 million per well in the fourth quarter and the average well cost in 2013 was 15% lower than 2012. Forest expects to see further improvement in well costs in 2014 through the continued optimization of drilling and completion techniques, the use of existing pad locations, and as the oil and gas gathering system and centralized production facility becomes operational during the second half of 2014.

Forest holds approximately 234,000 gross (162,000 net) acres in the greater Ark-La-Tex region, including East Texas, North Louisiana, and the Arkoma Basin. The Ark-La-Tex is largely held by production and provides repeatable and predictable drilling and recompletion opportunities in multiple natural gas, oil, and natural gas liquids horizons. During 2013, drilling activity focused on the liquids-rich Cotton Valley and other oil formations.

During the fourth quarter of 2013, one Cotton Valley well was completed with a 30-day average gross production rate of 8.4 MMcfe/d (35% liquids or 490 Bbls/d). Forest drilled a total of six wells in 2013 that had a 30-day average gross production rate of 8.7 MMcfe/d (40% liquids). Net sales volumes for the Ark-La-Tex averaged approximately 93 MMcfe/d in the fourth quarter of 2013.

A modified drilling and completion design was implemented in the latter part of 2013, which reduced the average well cost to approximately $7.5 million. This compares to an average well cost of $8.5 million for the other Cotton Valley wells drilled in 2013.

Based on an improving price environment, lower drilling and completion costs, and excellent well results, Forest has elected to increase activity in East Texas and recently added a second operated rig to the program. A third operated rig is expected to begin drilling during the second quarter of 2014. Forest anticipates drilling 20-25 wells in East Texas in 2014.

As part of an expanded Ark-La-Tex drilling program, Forest plans to continue development of a light sweet crude oil play in East Texas where it has successfully completed three horizontal producers since initiating this program in the second half of 2012. Forest currently holds approximately 19,000 gross (14,000 net) acres within this concentrated area. The Company is currently engaged in the integration of 3D seismic data with geological and well data and expects to commence additional drilling activity in this area during the second half of 2014.

Patrick R. McDonald, President and CEO, stated, “Our goals last year included accelerating development of our oil assets, improving our strategic direction by narrowing our operational focus, and reducing debt levels. In 2013, these objectives were achieved through the formation of a joint development partnership for our Eagle Ford asset and the execution of asset sales that generated proceeds of $1.3 billion. We were able to grow oil and liquids volumes by 55% and 41%, respectively, when compared to 2012 pro forma for divestitures. I am pleased that our team was able to accomplish these objectives.

“Our drilling and completion activity in the Eagle Ford during 2013 was primarily focused on lease expirations and delineation drilling in advance of transitioning to the development phase of the program. Our Eagle Ford average well costs continued to improve during 2013 as we capitalized on operational synergies, technological advancements and more efficient well drilling and completion designs. Our average well costs for 2013 were 15% lower than 2012 and we see the potential for further and significant reductions in 2014.

“As outlined in today’s update, we are electing to defer Eagle Ford drilling activity as we complete the reprocessing and interpretation of 3D seismic data and also evaluate the success of recent well completion designs. Importantly, we maintain a balanced portfolio of projects that provides attractive risk-adjusted rate-of-return opportunities. This will enable us to reallocate capital to our liquids-rich opportunities in the Ark-La-Tex to maintain a consistent level of drilling activity in 2014. This decision will result in lower oil growth for 2014; however, we believe this is a prudent capital allocation decision.”

Forest is updating its 2014 guidance that was initially provided on December 2, 2013, as follows:

A summary of 2014 guidance, including the changes outlined in today’s press release, is provided in the table below:


	Budget Low			Budget High
Drilling and Completion Capital Budget ($ million)	$	260		$	270
Non-Drilling Capital Budget:
Leasehold, Seismic, and Other ($ million)		10			15
Capitalized Overhead ($ million)		20			25
Total Capital Budget ($ million)	$	290		$	310

Average Net Sales Volumes (MMcfe/d)		120			130
% Natural Gas		65.0	%		65.0	%
% Oil		21.0	%		21.0	%
% Natural Gas Liquids		14.0	%		14.0	%

Production Expense ($ per Mcfe)	$	1.55		$	1.65
Depreciation, Depletion and Amortization ($ per Mcfe)	$	2.45		$	2.65
General and Administrative Expense ($ million)	$	28		$	30
Stock-Based Compensation ($ million)	$	9		$	11
Income Tax Rate		0	%		0	%

Incorporating the impact of a slower pace of development in the Eagle Ford and lower-than-expected fourth quarter well results, first quarter of 2014 net sales volumes are expected to average 105 – 110 MMcfe/d (67% natural gas and 33% liquids). Based on current projections of planned 2014 activity, the Company expects fourth quarter of 2014 average net sales volumes to average 145 – 150 MMcfe/d (63% natural gas and 37% liquids).

The following table provides a summary of 2013 average net sales volumes excluding asset sales and 2014 average net sales guidance by area:

Forest’s guidance for 2014 remains subject to the cautionary statements and limitations contained in Forest’s December 2, 2013, press release under the caption “2014 Guidance” as well as those stated below under the caption “Forward-Looking Statements.”

As of February 25, 2014, Forest had natural gas and oil derivatives in place for 2014 and 2015 covering the aggregate average daily volumes and weighted average prices shown below:

In connection with entering into certain 2014 oil swaps with premium hedged prices, Forest sold oil puts that gave the counterparties the option to put 2,000 Bbls/d to Forest at a weighted average price of $70.00 per Bbl on a monthly basis during 2014.

In connection with the execution of certain commodity swaps shown in the table above, Forest sold swaption instruments to counterparties in exchange for Forest receiving premium hedged prices on the swaps. The table below sets forth the outstanding swaptions as of February 25, 2014:

In addition to reporting net earnings (loss) as defined under generally accepted accounting principles (GAAP), Forest also presents adjusted net earnings, which is a non-GAAP performance measure. Adjusted net earnings consist of net earnings (loss) 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 (loss) (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 (loss) and revenues, to measure operating performance. The following table provides a reconciliation of net earnings, 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,
		2013			2012			2013			2012

Net earnings (loss)	$	106,219		$	(286,533	)	$	73,924		$	(1,288,931	)

Net gain on asset dispositions, net of tax		(129,012	)		-			(129,012	)		-
Ceiling test write-down of oil and natural gas properties, net of tax		36,806			178,032			36,806			634,047
Change in valuation allowance on deferred tax assets, net of non-deductible stock-based compensation costs, goodwill reduction, and other		(38,151	)		104,442			(26,799	)		577,480
Impairment of properties, net of tax		-			-			-			50,811
Employee-related asset disposition costs, net of tax		3,893			-			8,156			3,835
Rig stacking, net of tax		2,310			2,466			6,379			4,219
Net loss on debt extinguishment, net of tax		15,008			23,200			31,116			23,200
Unrealized losses (gains) on derivative instruments, net of tax		5,650			(4,615	)		19,811			25,037
Legal proceeding costs, net of tax		-			-			-			18,688
Adjusted net earnings	$	2,723		$	16,992		$	20,381		$	48,386

Earnings attributable to participating securities		(67	)		(406	)		(579	)		(1,138	)

Adjusted net earnings for diluted earnings per share	$	2,656		$	16,586		$	19,802		$	47,248

Weighted average number of diluted shares outstanding		116,559			115,477			116,125			114,960

Adjusted diluted earnings per share	$	0.02		$	0.14		$	0.17		$	0.41

In addition to reporting net earnings (loss) as defined under GAAP, Forest also presents adjusted net earnings before interest, income taxes, depreciation, depletion, amortization, and certain other items (adjusted EBITDA), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings (loss) 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 (loss) (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 and revenues, to measure operating performance. The following table provides a reconciliation of net earnings, the most directly comparable GAAP measure, to adjusted EBITDA for the periods presented (in thousands):


	Three Months Ended December 31,						Year Ended December 31,
		2013			2012			2013			2012

Net earnings (loss)	$	106,219		$	(286,533	)	$	73,924		$	(1,288,931	)

Income tax (benefit) expense		(245	)		(1,832	)		(707	)		173,437
Interest expense		24,790			37,899			119,829			141,831
Ceiling test write-down of oil and natural gas properties		57,636			278,654			57,636			992,404
Impairment of properties		-			-			-			79,529
Depreciation, depletion, and amortization		35,237			66,656			171,557			280,458
Unrealized losses (gains) on derivative instruments, net		8,847			(7,246	)		30,923			39,126
Gain on asset dispositions, net		(202,023	)		-			(202,023	)		-
Stock-based compensation		1,599			2,847			8,875			15,074
Accretion of asset retirement obligations		643			1,749			2,982			6,663
Employee-related asset disposition costs		5,357			-			11,178			1,851
Legal proceeding costs		-			-			-			29,251
Loss on debt extinguishment		23,502			36,312			48,725			36,312
Rig stacking		3,617			3,860			9,989			6,604
Adjusted EBITDA	$	65,179		$	132,366		$	332,888		$	513,609

In addition to reporting net cash provided by operating activities as defined under GAAP, Forest also presents adjusted discretionary cash flow, which is a non-GAAP liquidity measure. Adjusted discretionary cash flow consists of net cash provided by operating activities 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 (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 fluctuate 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, to measure operating performance. The following table provides a reconciliation of net cash provided by operating activities, 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,
		2013			2012			2013			2012

Net cash provided by operating activities	$	17,774		$	85,830		$	201,759		$	371,655

Changes in operating assets and liabilities:
Accounts receivable		(29,614	)		(2,503	)		(31,816	)		(11,573	)
Other current assets		2,392			1,796			(3,504	)		(2,630	)
Accounts payable and accrued liabilities		13,934			23,346			(1,560	)		21,164
Accrued interest and other		27,079			(15,799	)		28,996			(2,322	)
Current income tax credit/income tax-carryback ⁽¹⁾		-			-			-			(33,327	)
Employee-related asset disposition costs ⁽¹⁾		5,357			-			11,178			1,851
Legal proceeding costs⁽¹⁾		-			-			-			29,251

Adjusted discretionary cash flow	$	36,922		$	92,670		$	205,053		$	374,069

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.

	December 31, 2013				December 31, 2012
	Principal		Book⁽¹⁾		Principal		Book⁽¹⁾
Credit facility	$	-	$	-	$	65,000	$	65,000
7% Senior subordinated notes due 2013		-		-		12		12
8 1/2% Senior notes due 2014 ⁽²⁾		-		-		300,000		296,723
7 1/4% Senior notes due 2019 ⁽³⁾		577,914		578,092		1,000,000		1,000,365
7 1/2% Senior notes due 2020 ⁽³⁾		222,087		222,087		500,000		500,000
Total debt		800,001		800,179		1,865,012		1,862,100

Less: cash and cash equivalents		66,192		66,192		1,056		1,056

Net debt	$	733,809	$	733,987	$	1,863,956	$	1,861,044

⁽¹⁾		Book amounts include the principal amount of debt adjusted for unamortized premiums (discounts) on the issuance of certain senior notes of $0.2 million and $(2.9) million at December 31, 2013 and 2012, respectively.

⁽²⁾		In March 2013, Forest redeemed the $300 million 8 1/2% Senior notes due February 15, 2014 using the South Texas divestiture proceeds and borrowings on the credit facility.

⁽³⁾		In November 2013, Forest redeemed $700 million in aggregate principal amount of the 7 1/4% Senior notes due June 15, 2019 and 7 1/2% Senior notes due September 15, 2020 using a portion of the Texas Panhandle divestiture proceeds.

A conference call is scheduled for Wednesday, February 26, 2014, at 7:00 AM MT to discuss the release. You may access the call by dialing toll free 800.295.4740 (for U.S./Canada) and 617.614.3925 (for International) and request the Forest Oil teleconference (ID # 57263063). 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 of the conference call will be available through March 5, 2014. You may access the replay by dialing toll free 888.286.8010 (for U.S./Canada) and 617.801.6888 (for International), conference ID # 59682985. 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, intends, 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, timing and terms of any divestitures, and other forward-looking statements relating to Forest are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of liquids and natural gas.

These risks relating to Forest include, but are not limited to, oil and natural gas price volatility, its level of indebtedness, its ability to replace production, its ability to compete with larger producers, environmental risks, drilling and other operating risks, regulatory changes, credit risk of financial counterparties, risks of using third-party transportation and processing facilities, the decision to sell or offer for sale, or to determine not to sell any portion of its assets, the ability to enter into agreements relating to such sales on desirable terms or at all, the timing of any such agreements, the ability to consummate any such sales, the ability to realize the anticipated benefits of any such sales, the ability to determine the use of proceeds from any such sales, the ability to determine whether to reduce outstanding indebtedness and the amount and timing of any such reductions, 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. 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. Forest's principal reserves and producing properties are located in the United States in Arkansas, Louisiana, Oklahoma, and Texas. 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,			December 31,
				2013			2012
ASSETS			(In thousands)

Current assets:
	Cash and cash equivalents		$	66,192		$	1,056
	Accounts receivable			35,654			67,516
	Derivative instruments			5,192			40,190
	Other current assets			6,756			16,318
		Total current assets		113,794			125,080

Net property and equipment				818,569			1,754,238

Deferred income taxes				2,230			14,681
Goodwill				134,434			239,420
Derivative instruments				400			8,335
Other assets				48,525			60,108
			$	1,117,952		$	2,201,862

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
	Accounts payable and accrued liabilities		$	141,107		$	164,786
	Accrued interest			6,654			23,407
	Derivative instruments			4,542			9,347
	Deferred income taxes			2,230			14,681
	Other current liabilities			12,201			14,104
		Total current liabilities		166,734			226,325

Long-term debt				800,179			1,862,088
Asset retirement obligations				22,629			56,155
Derivative instruments				-			7,204
Other liabilities				73,941			92,914
		Total liabilities		1,063,483			2,244,686

Shareholders' equity:
	Common stock			11,940			11,825
	Capital surplus			2,554,997			2,541,859
	Accumulated deficit			(2,502,070	)		(2,575,994	)
	Accumulated other comprehensive loss			(10,398	)		(20,514	)
		Total shareholders' equity (deficit)		54,469			(42,824	)

			$	1,117,952		$	2,201,862

FOREST OIL CORPORATION Condensed Consolidated Statements of Operations (Unaudited)

			Three Months Ended						Year Ended
			December 31,						December 31,
				2013			2012			2013			2012
			(In thousands, except per share amounts)

Revenues:
	Oil, gas, and NGL sales		$	88,485		$	154,914		$	441,341		$	605,523
	Interest and other			5			13			331			136
		Total revenues		88,490			154,927			441,672			605,659

Costs, expenses, and other:
	Lease operating expenses			17,059			25,860			76,675			108,027
	Production and property taxes			2,945			7,314			14,857			34,249
	Transportation and processing costs			2,727			3,466			11,895			14,633
	General and administrative expense			11,933			14,041			54,826			59,262
	Depreciation, depletion, and amortization			35,237			66,656			171,557			280,458
	Ceiling test write-down of oil and natural gas properties			57,636			278,654			57,636			992,404
	Impairment of properties			-			-			-			79,529
	Interest expense			24,790			37,899			119,829			141,831
	Realized and unrealized losses (gains) on derivative instruments, net			4,283			(31,902	)		3,786			(72,646	)
	Other, net			(174,094	)		41,304			(142,606	)		83,406
		Total costs, expenses, and other		(17,484	)		443,292			368,455			1,721,153
	Earnings (loss) before income taxes			105,974			(288,365	)		73,217			(1,115,494	)
	Income tax (benefit) expense			(245	)		(1,832	)		(707	)		173,437
	Net earnings (loss)		$	106,219		$	(286,533	)	$	73,924		$	(1,288,931	)

Basic and diluted weighted average shares outstanding				116,559			115,477			116,125			114,958

Basic and diluted earnings (loss) per common share			$	0.89		$	(2.48	)	$	0.62		$	(11.21	)

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

				Three Months Ended						Year Ended
				December 31,						December 31,
					2013			2012			2013			2012
				(In thousands)
Operating activities:
Net earnings (loss)				$	106,219		$	(286,533	)	$	73,924		$	(1,288,931	)

Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
	Depreciation, depletion, and amortization				35,237			66,656			171,557			280,458
	Deferred income tax expense (benefit)				-			(15	)		-			208,975
	Unrealized losses (gains) on derivative instruments, net				8,847			(7,246	)		30,923			39,126
	Ceiling test write-down of oil and natural gas properties				57,636			278,654			57,636			992,404
	Impairment of properties				-			-			-			79,529
	Stock-based compensation				1,599			2,847			8,875			15,074
	Gain on asset dispositions, net				(202,023	)		-			(202,023	)		-
	Loss on debt extinguishment				23,502			36,312			48,725			36,312
	Other, net				548			1,995			4,258			13,347

	Changes in operating assets and liabilities:
		Accounts receivable			29,614			2,503			31,816			11,573
		Other current assets			(2,392	)		(1,796	)		3,504			2,630
		Accounts payable and accrued liabilities			(13,934	)		(23,346	)		1,560			(21,164	)
		Accrued interest and other current liabilities			(27,079	)		15,799			(28,996	)		2,322
			Net cash provided by operating activities		17,774			85,830			201,759			371,655

Investing activities:
Capital expenditures for property and equipment:
	Exploration, development, acquisition, and leasehold costs				(73,048	)		(122,654	)		(363,971	)		(721,536	)
	Other fixed assets				(251	)		(3,117	)		(1,517	)		(9,128	)
Proceeds from sales of assets					976,679			253,980			1,347,116			262,882
			Net cash provided (used) by investing activities		903,380			128,209			981,628			(467,782	)

Financing activities:
Proceeds from bank borrowings					72,000			593,000			529,000			1,244,000
Repayments of bank borrowings					(187,000	)		(528,000	)		(594,000	)		(1,284,000	)
Issuance of senior notes, net of issuance costs					-			-			-			491,250
Redemption of senior notes					(715,847	)		(330,709	)		(1,037,174	)		(330,709	)
Change in bank overdrafts					(25,541	)		13,499			(14,424	)		(24,217	)
Other, net					(695	)		58			(1,653	)		(2,153	)
			Net cash (used) provided by financing activities		(857,083	)		(252,152	)		(1,118,251	)		94,171

Net increase (decrease) in cash and cash equivalents					64,071			(38,113	)		65,136			(1,956	)
Cash and cash equivalents at beginning of period					2,121			39,169			1,056			3,012
Cash and cash equivalents at end of period				$	66,192		$	1,056		$	66,192		$	1,056

CONTACT:
Forest Oil Corporation
Larry C. Busnardo, 303-812-1441
VP – Investor Relations

	Three Months Ended December 31,		Year Ended December 31,
	2013		2013

Exploration and development	$	50,846	$	324,822
Land and leasehold acquisitions		1,933		7,117
		52,779		331,939

Add:
ARO, capitalized interest, and capitalized equity compensation		6,198		18,251
Total capital expenditures	$	58,977	$	350,190


	2014		2015
Natural gas swaps:
Contract volumes (Bbtu/d)		70.0		20.0
Weighted average price (per MMBtu)	$	4.38	$	4.20

Natural gas collars:
Contract volumes (Bbtu/d)		-		4.9
Ceiling price (per MMBtu)	$	-	$	5.31
Floor price (per MMBtu)	$	-	$	4.50

Oil swaps:
Contract volumes (MBbls/d)		3.5		-
Weighted average price (per Bbl)	$	95.34	$	-


	2015		2016
Natural gas swaptions:
Contract volumes (Bbtu/d)		-		10.0
Price (per MMBtu)	$	-	$	4.18

Oil swaptions:
Contract volumes (MBbls/d)		6.0		-
Weighted average price (per Bbl)	$	100.79	$	-


	Average Net Sales Volumes (MMcfe/d)
Region	1Q13A	2Q13A	3Q13A	4Q13A	1Q14E ⁽¹⁾	4Q14E ⁽¹⁾	2014 Guidance

Ark-La-Tex	102	96	96	93	89	125	100 - 109

Eagle Ford	12	13	18	18	18	22	20 - 21

Total	114	109	114	111	108	148	120 - 130

(1)		The current income tax credit/income tax carryback, employee-related asset disposition costs, and legal proceeding costs are non-recurring cash-settled items. Including the effect of these items, adjusted discretionary cash flow would have been $32 million and $93 million for the three months ended December 31, 2013 and 2012, respectively, and $194 million and $376 million for the years ended December 31, 2013 and 2012, respectively.