Edgar Filing: FOREST OIL CORP

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2009
Or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number 1-13515

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


New York (State or other jurisdiction of incorporation or organization)		25-0484900 (I.R.S. Employer Identification No.)

707 17th Street, Suite 3600 Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (303) 812-1400

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of "large accelerated filer", "accelerated filer", and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes ý No

As of October 30, 2009 there were 112,273,747 shares of the registrant's common stock, par value $.10 per share, outstanding.

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FOREST OIL CORPORATION
INDEX TO FORM 10-Q
September 30, 2009


Part I—FINANCIAL INFORMATION
	Item 1—Financial Statements
		Condensed Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008	1
		Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008	2
		Condensed Consolidated Statement of Shareholders' Equity for the Nine Months Ended September 30, 2009	3
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008	4
		Notes to Condensed Consolidated Financial Statements	5
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations		31
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		46
	Item 4—Controls and Procedures		50
Part II—OTHER INFORMATION
	Item 1A—Risk Factors		51
	Item 2—Unregistered Sales of Equity Securities and Use of Proceeds		55
	Item 6—Exhibits		57
Signatures			59

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands, Except Share Data)

				September 30, 2009

ASSETS
Current assets:
	Cash and cash equivalents			$	5,153		2,205
	Accounts receivable				95,537		157,226
	Derivative instruments				76,744		169,387
	Other investments				—		2,327
	Inventory				68,567		78,683
	Other current assets				56,000		63,221

		Total current assets			302,001		473,049
Property and equipment, at cost:
	Oil and gas properties, full cost method of accounting:
		Proved, net of accumulated depletion of $7,430,707 and $5,502,782			2,097,696		3,449,510
		Unproved			843,243		964,027

			Net oil and gas properties		2,940,939		4,413,537
	Other property and equipment, net of accumulated depreciation and amortization of $51,149 and $37,260				117,022		99,627

			Net property and equipment		3,057,961		4,513,164
Deferred income taxes					293,704		—
Goodwill					255,604		253,646
Derivative instruments					2,782		4,608
Other assets					47,383		38,331

				$	3,959,435		5,282,798

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable and accrued liabilities			$	193,785		424,941
	Accrued interest				39,872		7,143
	Derivative instruments				30,589		1,284
	Deferred income taxes				12,404		54,583
	Asset retirement obligations				3,456		5,852
	Other current liabilities				22,943		27,608

		Total current liabilities			303,049		521,411
Long-term debt					2,475,413		2,735,661
Asset retirement obligations					95,696		91,139
Derivative instruments					11,148		2,600
Deferred income taxes					—		185,587
Other liabilities					68,541		73,488

	Total liabilities				2,953,847		3,609,886
Shareholders' equity:
	Preferred stock, none issued and outstanding				—		—
	Common stock, 112,279,389 and 97,039,751 shares issued and outstanding				11,228		9,704
	Capital surplus				2,630,769		2,354,903
	Accumulated deficit				(1,697,614	)	(729,293	)
	Accumulated other comprehensive income				61,205		37,598

	Total shareholders' equity				1,005,588		1,672,912

				$	3,959,435		5,282,798

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

			Three Months Ended September 30,						Nine Months Ended September 30,

			2009			2008			2009			2008
			(In Thousands, Except Per Share Amounts)
Revenues:
	Oil and gas sales		$	177,184			474,237			553,473			1,365,902
	Interest and other			(42	)		379			602			2,823

Total revenues				177,142			474,616			554,075			1,368,725
Costs, expenses, and other:
	Lease operating expenses			34,938			44,912			114,205			120,890
	Production and property taxes			10,873			23,482			34,359			67,681
	Transportation and processing costs			5,352			4,874			15,918			14,440
	General and administrative			17,316			18,046			49,050			57,166
	Depreciation, depletion, and amortization			65,275			136,731			237,964			378,882
	Accretion of asset retirement obligations			2,014			1,871			6,195			5,622
	Ceiling test write-down of oil and gas properties			—			—			1,575,843			—
	Interest expense			42,653			30,429			122,373			86,265
	Realized and unrealized (gains) losses on derivative instruments, net			(5,665	)		(449,340	)		(112,212	)		74,358
	Gain on sale of assets			—			(21,063	)		—			(21,063	)
	Other, net			(4,074	)		21,725			(1,098	)		32,779

		Total costs, expenses, and other		168,682			(188,333	)		2,042,597			817,020
Earnings (loss) before income taxes				8,460			662,949			(1,488,522	)		551,705
Income tax:
	Current			—			2,961			1,505			6,939
	Deferred			(163,851	)		230,981			(521,706	)		188,509

		Total income tax		(163,851	)		233,942			(520,201	)		195,448
Net earnings (loss)			$	172,311			429,007			(968,321	)		356,257

Basic earnings (loss) per common share			$	1.53			4.77			(9.46	)		3.99

Diluted earnings (loss) per common share			$	1.53			4.71			(9.46	)		3.94

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(Unaudited)

		Common Stock

		Common Stock						Capital Surplus			Accumulated Deficit				Total Shareholders' Equity
		Shares			Amount			Capital Surplus			Accumulated Deficit				Total Shareholders' Equity
		(In Thousands)
Balances at December 31, 2008			97,040		$	9,704			2,354,903			(729,293	)	37,598		1,672,912
	Common stock issued, net of offering costs		14,375			1,438			254,779			—		—		256,217
	Exercise of stock options		3			—			48			—		—		48
	Employee stock purchase plan		106			11			1,237			—		—		1,248
	Restricted stock issued, net of cancellations		762			76			(76	)		—		—		—
	Amortization of stock-based compensation		—			—			20,604			—		—		20,604
	Restricted stock redeemed and other		(7	)		(1	)		(726	)		—		—		(727	)
Comprehensive loss:
	Net loss		—			—			—			(968,321	)	—		(968,321	)
	Unfunded postretirement benefits, net of tax		—			—			—			—		984		984
	Foreign currency translation		—			—			—			—		22,623		22,623

	Total comprehensive loss															(944,714	)

Balances at September 30, 2009			112,279		$	11,228			2,630,769			(1,697,614	)	61,205		1,005,588

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

			Nine Months Ended September 30,

			2009			2008
			(In Thousands)
Operating activities:
	Net earnings (loss)		$	(968,321	)		356,257
	Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
		Depreciation, depletion, and amortization		237,964			378,882
		Accretion of asset retirement obligations		6,195			5,622
		Deferred income tax		(521,706	)		188,509
		Stock-based compensation expense		12,948			14,093
		Unrealized losses (gains) on derivative instruments, net		132,216			(36,329	)
		Ceiling test write-down of oil and gas properties		1,575,843			—
		Unrealized foreign currency exchange (gains) losses, net		(15,609	)		6,771
		Unrealized losses on other investments, net		2,327			22,066
		Gain on sale of assets		—			(21,063	)
		Other, net		4,201			(2,837	)
	Changes in operating assets and liabilities:
		Accounts receivable		66,143			(1,234	)
		Other current assets		20,622			(50,275	)
		Accounts payable and accrued liabilities		(106,567	)		605
		Accrued interest and other current liabilities		27,317			21,383

Net cash provided by operating activities				473,573			882,450
Investing activities:
	Capital expenditures for property and equipment:
		Exploration, development, and acquisition costs		(512,266	)		(1,903,413	)
		Other fixed assets		(30,185	)		(50,928	)
	Proceeds from sales of assets			145,691			99,416
	Other, net			—			13,898

Net cash used by investing activities				(396,760	)		(1,841,027	)
Financing activities:
	Proceeds from bank borrowings			706,551			2,609,133
	Repayments of bank borrowings			(1,556,174	)		(1,674,884	)
	Issuance of 8¹/2% senior notes, net of issuance costs			559,767			—
	Issuance of 7¹/4% senior notes, net of issuance costs			—			247,188
	Redemption of 8% senior notes			—			(265,000	)
	Repurchases of 7% senior subordinated notes			(970	)		(4,710	)
	Proceeds from common stock offering, net of offering costs			256,217			—
	Proceeds from the exercise of options and from employee stock purchase plan			1,296			17,475
	Change in bank overdrafts			(36,303	)		26,093
	Other, net			(3,665	)		(5,804	)

Net cash (used) provided by financing activities				(73,281	)		949,491
Effect of exchange rate changes on cash				(584	)		(103	)

Net increase (decrease) in cash and cash equivalents				2,948			(9,189	)
Cash and cash equivalents at beginning of period				2,205			9,685

Cash and cash equivalents at end of period			$	5,153			496

Cash paid during the period for:
	Interest		$	92,711			74,802
	Income taxes			3,783			6,957

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) BASIS OF PRESENTATION

The Condensed Consolidated Financial Statements included herein are unaudited and include the accounts of Forest Oil Corporation and its consolidated subsidiaries (collectively, "Forest" or the "Company"). In the opinion of management, all adjustments, which are of a normal recurring nature, have been made which are necessary for a fair presentation of the financial position of Forest at September 30, 2009, the results of its operations for the three and nine months ended September 30, 2009 and 2008, and its cash flows for the nine months ended September 30, 2009 and 2008. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for liquids (oil, condensate, and natural gas liquids) and natural gas and other factors. Management has evaluated events and transactions occurring after the balance sheet date through November 6, 2009, the date that the financial statements were issued.

In the course of preparing the Condensed Consolidated Financial Statements, management makes various assumptions, judgments, and estimates to determine the reported amounts of assets, liabilities, revenues, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of oil and gas reserves used in calculating depletion, the amount of future net revenues used in computing the ceiling test limitations, and the amount of future capital costs and abandonment obligations used in such calculations, determining impairments of investments in unproved properties, valuing deferred tax assets and goodwill, and estimating fair values of financial instruments, including derivative instruments.

Certain amounts in the prior year financial statements have been reclassified to conform to the 2009 financial statement presentation.

For a more complete understanding of Forest's operations, financial position, and accounting policies, reference is made to the consolidated financial statements of Forest, and related notes thereto, filed with Forest's Annual Report on Form 10-K for the year ended December 31, 2008, previously filed with the Securities and Exchange Commission.

(2) EARNINGS (LOSS) PER SHARE AND COMPREHENSIVE EARNINGS (LOSS)

Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Under the treasury stock method, diluted earnings (loss) per share is computed by dividing net earnings (loss) adjusted for the effects of certain contracts that provide the issuer or holder with a choice between settlement methods by the weighted average number of common shares outstanding adjusted for the dilutive effect, if any, of potential common shares (i.e. stock options, unvested restricted stock grants, and unvested phantom stock units that may be settled in shares). No potential common shares shall be included in the computation of any diluted per share amount when a net loss exists.

The two-class method of computing earnings per share is required for those entities that have participating securities or multiple classes of common stock. The two-class method is an earnings

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(2) EARNINGS (LOSS) PER SHARE AND COMPREHENSIVE EARNINGS (LOSS) (Continued)

allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. In June 2008, the Financial Accounting Standards Board ("FASB") issued authoritative guidance that addressed whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method. This guidance was effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. Accordingly, Forest adopted this guidance as of January 1, 2009. All prior period earnings per share data presented have been adjusted retrospectively to conform to the provisions of this guidance.

Restricted stock issued under Forest's stock incentive plans has the right to receive non-forfeitable cash dividends, participating on an equal basis with common stock. Phantom stock units issued to directors under Forest's stock incentive plans also have the right to receive non-forfeitable cash dividends, participating on an equal basis with common stock, while phantom stock units issued to employees do not participate in dividends. Stock options issued under Forest's stock incentive plans do not participate in dividends. Therefore, restricted stock issued to employees and directors and phantom stock units issued to directors are participating securities and earnings must now be allocated to both common stock and these participating securities under the two-class method. However, these participating securities do not have a contractual obligation to share in Forest's losses. Therefore, in periods of net loss, none of the loss is allocated to these participating securities, consequently, the adoption of this guidance will have no impact on Forest's basic earnings per share for those periods. In periods of net earnings, however, both basic and diluted earnings per share calculated under the two-class method will likely be lower than they would have been prior to the adoption of this guidance.

Stock options, unvested restricted stock grants, and unvested phantom stock units that may be settled in shares were not included in the calculation of diluted loss per share for the nine months ended September 30, 2009 as their inclusion would have an antidilutive effect. Unvested restricted stock grants and unvested participating phantom stock units were not included in the calculation of diluted earnings per share for the three and nine months ended September 30, 2008 and unvested restricted stock grants were not included in the calculation of diluted earnings per share for the three months ended September 30, 2009 as their inclusion would have an antidilutive effect.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(2) EARNINGS (LOSS) PER SHARE AND COMPREHENSIVE EARNINGS (LOSS) (Continued)

The following sets forth the calculation of basic and diluted earnings (loss) per share for the periods presented.

	Three Months Ended September 30,						Nine Months Ended September 30,

	2009			2008			2009			2008
	(In Thousands, Except Per Share Amounts)
Net earnings (loss)	$	172,311			429,007			(968,321	)		356,257
Net earnings attributable to participating securities		(3,384	)		(9,027	)		—			(6,392	)

Net earnings (loss) attributable to common stock for basic earnings per share		168,927			419,980			(968,321	)		349,865
Adjustment for liability-classified stock-based compensation awards		(21	)		(519	)		—			195
Adjustment to net earnings attributable to participating securities		—			11			—			(3	)

Net earnings (loss) for diluted earnings per share	$	168,906			419,472			(968,321	)		350,057

Weighted average common shares outstanding during the period		110,054			87,987			102,366			87,667
Dilutive effects of potential common shares		168			1,058			—			1,155

Weighted average common shares outstanding, including the effects of dilutive potential common shares		110,222			89,045			102,366			88,822

Basic earnings (loss) per common share	$	1.53			4.77			(9.46	)		3.99

Diluted earnings (loss) per common share	$	1.53			4.71			(9.46	)		3.94

Comprehensive Earnings (Loss)

Comprehensive earnings (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under U.S. generally accepted accounting principles are reported as separate components of shareholders' equity instead of net earnings (loss). Items included in Forest's other comprehensive income (loss) for the three and nine months ended September 30, 2009 and 2008 are foreign currency gains and losses related to the translation of the assets and liabilities of Forest's Canadian operations and changes in unfunded postretirement benefits.

The components of comprehensive earnings (loss) are as follows:

		Three Months Ended September 30,					Nine Months Ended September 30,

		2009		2008			2009			2008
		(In Thousands)
Net earnings (loss)		$	172,311		429,007			(968,321	)		356,257
Other comprehensive income (loss):
	Foreign currency translation gains (losses)		18,591		(18,663	)		22,623			(30,645	)
	Unfunded postretirement benefits, net of tax		316		(7	)		984			(7	)

Total comprehensive earnings (loss)		$	191,218		410,337			(944,714	)		325,605

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) STOCK-BASED COMPENSATION

The table below sets forth total stock-based compensation recorded during the three and nine months ended September 30, 2009 and 2008, and the remaining unamortized amounts and the weighted average amortization period remaining as of September 30, 2009.

		Stock Options

		(In Thousands)
Three months ended September 30, 2009:
	Total stock-based compensation costs	$	196		6,938		972		8,106
	Less: stock-based compensation costs capitalized		(70	)	(2,664	)	(470	)	(3,204	)

	Stock-based compensation costs expensed	$	126		4,274		502		4,902

Nine months ended September 30, 2009:
	Total stock-based compensation costs	$	533		19,586		1,273		21,392
	Less: stock-based compensation costs capitalized		(222	)	(7,751	)	(623	)	(8,596	)

	Stock-based compensation costs expensed	$	311		11,835		650		12,796

Unamortized stock-based compensation costs as of September 30, 2009		$	1,611		40,268		6,109	⁽²⁾	47,988
Weighted average amortization period remaining			1.3 years		1.7 years		2.4 years		1.8 years
Three months ended September 30, 2008:
	Total stock-based compensation costs	$	745		7,237		(1,030	)	6,952
	Less: stock-based compensation costs capitalized		(292	)	(2,636	)	658		(2,270	)

	Stock-based compensation costs expensed	$	453		4,601		(372	)	4,682

Nine months ended September 30, 2008:
	Total stock-based compensation costs	$	2,274		17,429		2,788		22,491
	Less: stock-based compensation costs capitalized		(940	)	(6,172	)	(1,683	)	(8,795	)

	Stock-based compensation costs expensed	$	1,334		11,257		1,105		13,696

⁽¹⁾: The Company also maintains an employee stock purchase plan (which is not included in the table) under which $.1 million and $.5 million of compensation cost was recognized for the three and nine months ended September 30, 2009, respectively, and $.1 million and $.4 million of compensation cost was recognized for the three and nine months ended September 30, 2008, respectively.
⁽²⁾: Based on the closing price of the Company's common stock on September 30, 2009.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) STOCK-BASED COMPENSATION (Continued)

Stock Options

The following table summarizes stock option activity in the Company's stock-based compensation plans for the nine months ended September 30, 2009.

			Weighted Average Exercise Price		Aggregate Intrinsic Value (In Thousands)⁽¹⁾

Outstanding at January 1, 2009	2,097,267		$	21.13	$	376	1,898,316
Granted	—			—
Exercised	(3,344	)	$	14.56		7
Cancelled	(102,782	)	$	23.14

Outstanding at September 30, 2009	1,991,141		$	21.03		3,602	1,890,034

⁽¹⁾: The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.

Restricted Stock and Phantom Stock Units

The following table summarizes the restricted stock and phantom stock unit activity in the Company's stock-based compensation plans for the nine months ended September 30, 2009.

	Restricted Stock					Phantom Stock Units⁽¹⁾

	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value
Unvested at January 1, 2009		1,490,795		$	52.31		163,954		$	51.10
Awarded		802,918			18.11		322,403			17.96
Vested		(51,445	)		48.27		(7,429	)		42.82
Forfeited		(40,685	)		48.17		(18,459	)		46.13

Unvested at September 30, 2009		2,201,583			40.01		460,469			28.23

⁽¹⁾: Of the unvested units of phantom stock at September 30, 2009, 224,500 units can be settled in cash, shares of common stock, or a combination of both, while the remaining 235,969 units can only be settled in cash. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(4) DEBT

The components of debt are as follows:

	September 30, 2009									December 31, 2008

	Principal		Unamortized Premium (Discount)			Other⁽³⁾		Total		Principal		Unamortized Premium (Discount)			Other⁽³⁾		Total
	(In Thousands)
U.S. Credit Facility	$	318,000		—			—		318,000		1,190,000		—			—		1,190,000
Canadian Credit Facility		135,430		—			—		135,430		94,415		—			—		94,415
8% Senior Notes due 2011		285,000		2,906			1,849		289,755		285,000		3,875			2,475		291,350
7% Senior Subordinated Notes due 2013⁽¹⁾		112		(2	)		—		110		1,112		(25	)		—		1,087
8¹/2% Senior Notes due 2014⁽²⁾		600,000		(25,497	)		—		574,503		—		—			—		—
7³/4% Senior Notes due 2014		150,000		(1,094	)		8,161		157,067		150,000		(1,273	)		9,492		158,219
7¹/4% Senior Notes due 2019		1,000,000		548			—		1,000,548		1,000,000		590			—		1,000,590

Total debt	$	2,488,542		(23,139	)		10,010		2,475,413		2,720,527		3,167			11,967		2,735,661

⁽¹⁾: In June 2009, the Company repurchased $1.0 million in principal amount of 7% senior subordinated notes due 2013 at 97% of par value.
⁽²⁾: In February 2009, the Company issued $600 million in principal amount of 8¹/2% senior notes due 2014 at 95.15% of par for proceeds of $559.8 million (net of related initial purchaser discounts) and used the net proceeds to pay down outstanding balances on the Company's U.S. credit facility.
⁽³⁾: Represents the unamortized portion of gains realized upon termination of interest rate swaps that were accounted for as fair value hedges. The gains are being amortized as a reduction of interest expense over the terms of the notes.

Bank Credit Facilities

Forest's combined credit facilities consist of a $1.65 billion U.S. credit facility (the "U.S. Facility") with a syndicate of banks led by JPMorgan Chase Bank, N.A., and a $150 million Canadian credit facility (the "Canadian Facility," and together with the U.S. Facility, the "Credit Facilities") with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Credit Facilities will mature in June 2012.

Forest's availability under the Credit Facilities is governed by a borrowing base (the "Global Borrowing Base"). As a result of issuing $600 million of 8¹/2% senior notes due 2014 in February 2009, Forest's borrowing base was lowered from $1.8 billion to $1.62 billion effective February 17, 2009. As a result of the adjustment to the Global Borrowing Base, Forest reallocated amounts under the U.S. Facility and Canadian Facility and currently has allocated $1.47 billion to the U.S. Facility and $150 million to the Canadian Facility. In October 2009, Forest's bank group reaffirmed Forest's $1.62 billion Global Borrowing Base. The next redetermination of the borrowing base is expected to occur in the second quarter of 2010.

At September 30, 2009, there were outstanding borrowings of $318.0 million under the U.S. Facility at a weighted average interest rate of 1.31%, and there were outstanding borrowings of $135.4 million under the Canadian Facility at a weighted average interest rate of 1.96%. The Company also had used the Credit Facilities for $8.0 million in letters of credit, leaving availability under the Credit Facilities of $1.2 billion at September 30, 2009. Effective as of March 16, 2009, the Company

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(Unaudited)

(4) DEBT (Continued)

entered into an amendment to its Credit Facilities that amended certain definitions and covenants of the credit agreements, including the total debt outstanding-to-EBITDA ratio.

8¹/2% Senior Notes Due 2014

On February 17, 2009, Forest issued $600 million in principal amount of 8¹/2% senior notes due 2014 (the "8¹/2% Notes") at 95.15% of par for net proceeds of $559.8 million, after deducting initial purchaser discounts. Proceeds from the 8¹/2% Notes were used to pay down outstanding balances on the Company's U.S. Facility. The 8¹/2% Notes are jointly and severally guaranteed by Forest Oil Permian Corporation, a wholly-owned subsidiary of Forest, on an unsecured basis. Interest is payable on February 15 and August 15 of each year. The 8¹/2% Notes will mature on February 15, 2014. Forest may redeem up to 35% of the 8¹/2% Notes at any time prior to February 15, 2012, on one or more occasions, with the proceeds from certain equity offerings at a redemption price equal to 108.5% of the principal amount, plus accrued but unpaid interest.

Forest may also redeem the 8¹/2% Notes in whole or in part and at any time, at a "make-whole" redemption price equal to the greater of (i) 100% of the principal amount of the 8¹/2% Notes to be redeemed or (ii) the sum of the remaining scheduled payments of principal and interest on the 8¹/2% Notes discounted to the date of redemption at an applicable Treasury yield rate plus 0.50%, plus, in either case, accrued but unpaid interest.

7% Senior Subordinated Notes Due 2013

On June 19, 2009, Forest repurchased $1.0 million in principal amount of 7% senior subordinated notes due 2013 at 97% of par value.

(5) SHAREHOLDERS' EQUITY

In May 2009, the Company issued 14,375,000 shares of common stock at a price of $18.25 per share. Net proceeds from this offering were $256.2 million after deducting underwriting discounts and commissions and offering expenses. Forest used the net proceeds from the offering to repay a portion of the outstanding borrowings under its U.S. credit facility.

(6) OIL AND GAS PROPERTIES

Full Cost Method of Accounting

The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which the Company has operations. During the periods presented, the Company's primary oil and gas operations were conducted in the United States and Canada. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. During the three months ended September 30, 2009 and 2008, Forest capitalized $11.4 million and $11.8 million of general and administrative costs (including stock-based compensation), respectively. During the nine months ended September 30, 2009 and 2008, Forest capitalized $33.5 million and $38.7 million of general and

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(6) OIL AND GAS PROPERTIES (Continued)

administrative costs (including stock-based compensation), respectively. Interest costs related to significant unproved properties that are under development are also capitalized to oil and gas properties. During the three months ended September 30, 2009 and 2008, the Company capitalized $2.5 million and $4.0 million, respectively, of interest costs attributed to unproved properties. During the nine months ended September 30, 2009 and 2008, the Company capitalized $9.3 million and $14.6 million, respectively, of interest costs attributed to unproved properties.

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves.

Investments in unproved properties are not depleted pending determination of the existence of proved reserves; however, unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within each separate cost center. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. As a result of this limitation on capitalized costs, in the first quarter of 2009, the Company recorded a non-cash ceiling test write-down of oil and gas property costs of $1.377 billion in its United States cost center and $199.0 million in its Canada cost center. Accordingly, the accompanying condensed consolidated financial statements reflect a total non-cash ceiling test write-down of oil and gas properties of $1.576 billion for the nine months ended September 30, 2009.

Gain or loss is not recognized on the sale of oil and gas properties unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and gas reserves attributable to a cost center.

(7) ASSET RETIREMENT OBLIGATIONS

Forest records the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset.

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(Unaudited)

(7) ASSET RETIREMENT OBLIGATIONS (Continued)

Subsequent to initial measurement, the asset retirement liability is required to be accreted each period to its present value. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Forest's asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

The following table summarizes the activity for Forest's asset retirement obligations for the nine months ended September 30, 2009 and 2008.

	Nine Months Ended September 30,

	2009			2008
	(In Thousands)
Asset retirement obligations at beginning of period	$	96,991			90,505
Accretion expense		6,195			5,622
Liabilities incurred		4,676			8,455
Liabilities settled		(2,474	)		(3,152	)
Disposition of properties		(5,283	)		(3,692	)
Liabilities assumed		—			2,747
Revisions of estimated liabilities		(2,494	)		737
Impact of foreign currency exchange rate		1,541			(1,106	)

Asset retirement obligations at end of period		99,152			100,116
Less: current asset retirement obligations		(3,456	)		(4,204	)

Long-term asset retirement obligations	$	95,696			95,912

(8) FAIR VALUE MEASUREMENTS

In September 2006, the FASB issued authoritative guidance that clarified the definition of fair value, established a framework for measuring fair value, and expanded disclosures about fair value measurements. The Company adopted the provisions of this guidance as of January 1, 2008 for all financial and nonfinancial assets and liabilities recognized or disclosed at fair value on a recurring basis. The Company has also adopted this guidance as it relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g. those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of goodwill and other long-lived assets) as of January 1, 2009. The adoption of this guidance did not materially impact the Company's financial position, results of operations, or cash flow.

The authoritative guidance established a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions. The Company uses the income approach to value financial instruments under the Level 2 and Level 3 hierarchies.

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(Unaudited)

(8) FAIR VALUE MEASUREMENTS (Continued)

The Company's assets and liabilities measured at fair value on a recurring basis at September 30, 2009 are set forth in the table below.

Description		Using Significant Other Observable Inputs (Level 2)

		(In Thousands)
Assets:
	Derivative instruments⁽¹⁾	$	79,526	—	79,526
	Equity securities⁽²⁾		—	—	—
	Debt securities⁽²⁾		—	—	—
Liabilities:
	Derivative instruments⁽¹⁾		41,737	—	41,737

⁽¹⁾: The Company's derivative assets and liabilities include oil and gas commodity swaps and collars as well as interest rate swaps and swaptions (see Note 9). The Company utilized present value techniques for valuing its swaps and option-pricing models for valuing its collars. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, the Company's derivative instruments are included within the Level 2 fair value hierarchy.
⁽²⁾: The Company's equity and debt securities are comprised of a zero coupon senior subordinated note due from Pacific Energy Resources, Ltd. ("PERL") in 2014 at a principal amount at stated maturity of $60.8 million (the "PERL Note") and 10 million shares of PERL common stock (the "PERL Shares"), both received as consideration for the sale of the Company's Alaska assets in 2007. The PERL Shares and Note, each presently valued at zero, are included within the Level 3 fair value hierarchy. The Company used its own assumptions about the assumptions that market participants would use regarding future cash flows and risk-adjusted discount rates in valuing the PERL Shares and Note. In March 2009, PERL filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. PERL has indicated that the value of its assets is less than the amount of its senior unsubordinated debt.

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(8) FAIR VALUE MEASUREMENTS (Continued)

The following table presents a reconciliation of the beginning and ending balances of the Company's assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2009 and 2008.

			Three Months Ended September 30,							Nine Months Ended September 30,

			2009				2008			2009						2008
			Equity Securities		Debt Securities		Debt Securities			Equity Securities			Debt Securities			Debt Securities
			(In Thousands)
Balance at beginning of period			$	—		—		16,742			—			1,670			15,023
	Total gains or (losses) (realized/unrealized):
		Included in earnings		—		—		(6,199	)		(657	)		(1,670	)		(4,480	)
		Included in other comprehensive income		—		—		—			—			—			—
		Purchases, sales, issuances, and settlements (net)		—		—		—			—			—			—
		Transfers in and/or out of Level 3⁽¹⁾		—		—		—			657			—			—

Balance at end of period			$	—		—		10,543			—			—			10,543

The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at end of period			$	—		—		(6,199	)		(657	)		(1,670	)		(6,154	)

⁽¹⁾: The Company's investment in PERL common stock was previously valued within the Level 1 fair value hierarchy until March 2009 when PERL's common stock was suspended from trading for failure to meet the continued stock exchange listing requirements. As a result, the Company's investment in PERL common stock, presently valued at zero, is now included within the Level 3 fair value hierarchy as there is no longer an active market for this investment.

Gains and losses (realized and unrealized) included in earnings related to the Company's assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three

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(8) FAIR VALUE MEASUREMENTS (Continued)

and nine months ended September 30, 2009 and 2008 are reported in the Condensed Consolidated Statements of Operations as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,

	2009				2008		2009				2008
	Equity Securities		Debt Securities		Debt Securities		Equity Securities		Debt Securities		Debt Securities
	Other, net		Other, net		Other, net		Other, net		Other, net		Other, net		Interest and other⁽¹⁾
	(In Thousands)
Total losses or (gains) included in earnings for the period	$	—		—		6,199		657		1,670		6,154		(1,674	)

Change in unrealized losses or (gains) relating to assets still held at end of period	$	—		—		6,199		657		1,670		6,154		—

⁽¹⁾: Represents imputed interest income on the PERL Note.

The fair values and carrying amounts of the Company's financial instruments are summarized below as of the dates indicated.

		September 30, 2009				December 31, 2008

		Carrying Amount		Fair Value⁽¹⁾		Carrying Amount		Fair Value⁽¹⁾
		(In Thousands)
Assets:
	Cash and cash equivalents	$	5,153		5,153		2,205		2,205
	Other investments		—		—		2,327		2,327
	Derivative instruments		79,526		79,526		173,995		173,995
Liabilities:
	Derivative instruments		41,737		41,737		3,884		3,884
	Credit facilities		453,430		453,430		1,284,415		1,284,415
	8% senior notes due 2011		289,755		289,275		291,350		256,500
	7% senior subordinated notes due 2013		110		112		1,087		912
	8¹/2% senior notes due 2014		574,503		612,000		—		—
	7³/4% senior notes due 2014		157,067		148,500		158,219		123,000
	7¹/4% senior notes due 2019		1,000,548		940,000		1,000,590		780,000

⁽¹⁾: The Company used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amount of cash and cash equivalents approximated fair value due to the short original maturities (three months or less) and high liquidity of the cash equivalents. The carrying amount of the Credit Facilities approximated fair value since borrowings bear interest at variable rates. The fair values of the senior notes and senior subordinated notes were estimated based on quoted market prices, if available, or quoted market prices of comparable instruments. The fair values of the derivative instruments and other investments are discussed above. See also Note 9 to the Condensed Consolidated Financial Statements for more information on the derivative instruments.

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(Unaudited)

(9) DERIVATIVE INSTRUMENTS

Commodity Derivatives

Forest periodically enters into derivative instruments such as swap, basis swap, and collar agreements as an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow and to manage the exposure to commodity price risk. Forest's commodity derivative instruments generally serve as effective economic hedges of commodity price exposure; however, the Company has elected not to designate its derivatives as hedging instruments. As such, the Company recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the Condensed Consolidated Statement of Operations.

In March 2008, the FASB issued authoritative guidance that requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This guidance was effective for fiscal years and interim periods beginning after November 15, 2008. Accordingly, Forest has adopted this guidance as of January 1, 2009.

The table below sets forth Forest's outstanding commodity swaps and collars as of September 30, 2009.

		Natural Gas (NYMEX HH)					Oil (NYMEX WTI)

		Bbtu Per Day			Weighted Average Hedged Price per MMBtu		Barrels Per Day		Weighted Average Hedged Price per Bbl
Swaps:
	October 2009		210	⁽¹⁾	$	7.33		4,500	$	69.01
	November 2009 - December 2009		160	⁽¹⁾		8.24		4,500		69.01
	Calendar 2010		160			6.34		2,500		75.27
Costless Collars:
	October 2009 - December 2009		40			$7.31/9.76⁽²⁾		—	$	—
	Calendar 2010		—			—		1,000		60.00/97.00⁽²⁾

⁽¹⁾: 10 Bbtu per day is subject to a $6.00 written put.
⁽²⁾: Represents weighted average hedged floor and ceiling price per unit.

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(Unaudited)

(9) DERIVATIVE INSTRUMENTS (Continued)

Subsequent to September 30, 2009, through October 31, 2009, Forest entered into additional commodity swaps and collars as set forth in the table below.

		Natural Gas (NYMEX HH)				Oil (NYMEX WTI)

		Bbtu Per Day		Weighted Average Hedged Price per MMBtu		Barrels Per Day		Hedged Price per Bbl
Swaps:
	November 2009 - December 2009		50	$	5.43		—	$	—
	Calendar 2010		—		—		500		80.00
Costless Collars:
	Calendar 2010		—		—		1,000		60.00/100.00⁽¹⁾

⁽¹⁾: Represents hedged floor and ceiling price per Bbl.

Forest also uses basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the index price at which the natural gas production is sold. The table below sets forth Forest's outstanding basis swaps as of September 30, 2009.

	Index		Weighted Average Hedged Price Differential per MMBtu

October 2009 - December 2009	AECO	25	$	(.65	)
October 2009 - December 2009	Centerpoint	30		(.95	)
October 2009 - December 2009	Houston Ship Channel	50		(.33	)
October 2009 - December 2009	Mid Continent	60		(1.04	)
October 2009 - December 2009	NGPL TXOK	40		(.53	)
Calendar 2010	Centerpoint	30		(.95	)
Calendar 2010	Houston Ship Channel	50		(.29	)
Calendar 2010	Mid Continent	60		(1.04	)
Calendar 2010	NGPL TXOK	40		(.44	)

Interest Rate Derivatives

Forest periodically enters into interest rate derivative agreements in an attempt to normalize the mix of fixed and floating interest rates within its debt portfolio. The table below sets forth Forest's outstanding fixed-to-floating interest rate swaps as of September 30, 2009.

Swap Term		Notional Amount (In Thousands)			Weighted Average Floating Rate		Weighted Average Fixed Rate

October 2009 - February 2014		$	500,000		1 month LIBOR + 5.89%			8.50	%

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(Unaudited)

(9) DERIVATIVE INSTRUMENTS (Continued)

Subsequent to September 30, 2009, through October 31, 2009, Forest entered into an additional interest rate swap as set forth in the table below.

In addition to the interest rate swaps, during the nine months ended September 30, 2009, Forest entered into certain interest rate swaptions, which enable the counterparties to exercise options to enter into interest rate swaps with Forest in exchange for a premium paid to Forest. The premiums received on these swaptions are amortized as realized gains on derivatives over the term of the related swaption. Forest entered into these interest rate swaptions because its targeted floating interest rates were not attainable at that time in the interest rate swap market yet premiums were available from counterparties for the option to swap Forest's 8.5% fixed rate for the floating rates it had targeted. The table below sets forth Forest's outstanding interest rate swaption as of September 30, 2009.

Subsequent to September 30, 2009, the swaption above expired unexercised and, through October 31, 2009, Forest entered into an additional interest rate swaption as set forth in the table below.

The table below summarizes the location and fair value amounts of Forest's derivative instruments reported in the Condensed Consolidated Balance Sheets as of the dates indicated. These derivative instruments are not designated as hedging instruments for accounting purposes. For financial reporting purposes, Forest does not offset asset and liability fair value amounts recognized for derivative

instruments with the same counterparty under its master netting arrangements. See Note 8 to the Condensed Consolidated Financial Statements for more information on Forest's derivative instruments.

The table below summarizes the location and amount of derivative instrument gains and losses reported in the Condensed Consolidated Statements of Operations for the periods indicated. These derivative instruments are not designated as hedging instruments for accounting purposes, as such the gains and losses are included in "Costs, expenses, and other" in the Condensed Consolidated Statements of Operations.

Due to the volatility of oil and natural gas prices, the estimated fair values of Forest's commodity derivative instruments are subject to large fluctuations from period to period. Forest has experienced the effects of these commodity price fluctuations in both the current period and prior periods and expects that volatility in commodity prices will continue.

Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. ("ISDA") Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes, with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties' requirements and the specific types of derivatives to be traded. None of these counterparties require collateral beyond that already pledged under the Credit Facilities. All but one of the counterparties is a lender, or an affiliate of a lender, under the Credit Facilities, which provide that any security granted by Forest under the Credit Facilities shall also extend to and be available to those lenders that are counterparties to derivative transactions with Forest. The remaining counterparty, a purchaser of Forest's natural gas production, generally owes money to Forest and therefore does not require collateral under the ISDA Master Agreement and Schedule it has executed with Forest. The Credit Facilities are collateralized by a portion of the Company's assets. The Company is required to mortgage and grant a security interest in the greater of (i) 75% of the present value of its consolidated proved oil and gas properties or (ii) 1.875 multiplied by the allocated U.S. borrowing base. The Company is also required to and has pledged the stock of several subsidiaries to the lenders to secure the Credit Facilities. Under certain circumstances, the Company could be obligated to pledge additional assets as collateral. If Forest's corporate credit ratings assigned by Moody's and S&P improve and meet pre-established levels, the collateral requirements would cease to apply and, at the Company's request, the banks would release their liens on and security interests in the Company's properties. In addition to these collateral requirements, one of the Company's subsidiaries, Forest Oil Permian Corporation, is a subsidiary guarantor of the Credit Facilities.

The ISDA Master Agreements and Schedules contain cross-default provisions whereby a default under the Credit Facilities will also cause a default under the derivative agreements. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, a failure of the liens securing the Credit Facilities, and an event of default under the Canadian Facility. In addition, bankruptcy and insolvency events with respect to Forest or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facilities. None of these events of default are specifically credit-related, but some could arise due to a general deterioration of Forest's credit. The ISDA Master Agreements and Schedules contain a further credit-related termination event that would occur if Forest were to merge with another entity and the creditworthiness of the resulting entity was materially weaker than that of Forest.

The vast majority of Forest's derivative counterparties are all financial institutions that are engaged in similar activities and have similar economic characteristics that, in general, could cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.

Forest does not require the posting of collateral for its benefit under its derivative agreements. However, Forest's ISDA Master Agreements contain netting provisions whereby if on any date amounts would otherwise be payable by each party to the other, then on such date the party that owes the larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party's obligations. These provisions apply to all derivative transactions with the particular counterparty. If all counterparties failed, Forest would be exposed to a risk of loss equal to this net amount owed to us, the fair value of which was $65.1 million at September 30, 2009. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net obligations due to it under the derivative agreements. At September 30, 2009, Forest owed a net derivative liability to five counterparties, the fair value of which was $27.3 million.

A reconciliation of income tax computed by applying the United States statutory federal income tax rate is as follows:

In assessing the need for a valuation allowance on the Company's deferred tax assets, all available evidence, both negative and positive, was considered in determining whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on this assessment, Forest had a valuation allowance of $3.1 million against its deferred tax assets as of September 30, 2009. Forest's evaluation of the amount of the deferred tax asset considered more likely than not to be realizable will likely change in future periods as estimates of Forest's future income change due to changes in expected future oil and gas prices and other factors, and these changes could be material.

The table below sets forth the components of "Other, net" within "Costs, expenses, and other" of the Condensed Consolidated Statements of Operations for the periods indicated.

At September 30, 2009, Forest conducted operations in one industry segment, oil and gas exploration and production, and had three reportable geographical business segments: United States, Canada, and International. Forest's remaining activities were not significant and therefore were not reported as a separate segment, but have been included as a reconciling item in the information below. The segments were determined based upon the geographical location of operations in each business segment. The segment data presented below was prepared on the same basis as the Condensed Consolidated Financial Statements.

A reconciliation of segment earnings (loss) to consolidated earnings (loss) before income taxes is as follows:

A reconciliation of segment earnings to consolidated earnings before income taxes is as follows:

The following tables set forth information regarding the Company's total assets by segment and long-lived assets by geographic area. Long-lived assets include net property and equipment and goodwill.

The Company's 8% senior notes due 2011, 8¹/2% senior notes due 2014, 7³/4% senior notes due 2014, and 7¹/4% senior notes due 2019 have been fully and unconditionally guaranteed by Forest Oil Permian Corporation, a wholly-owned subsidiary of the Company (the "Subsidiary Guarantor"). The Company's remaining subsidiaries (the "Non-Guarantor Subsidiaries") have not provided guarantees. Based on this distinction, the following presents condensed consolidating financial information as of September 30, 2009 and December 31, 2008 and for the three and nine months ended September 30, 2009 and 2008 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Elimination entries presented are necessary to combine the entities.

In December 2008, the FASB issued authoritative guidance on an employer's disclosures about plan assets of a defined benefit pension or other postretirement benefit plan. This guidance states that disclosures concerning plan assets should provide users of financial statements with an understanding of:

investment policies and strategies; categories of plan assets; fair value measurements of plan assets; and significant concentrations of risk. The disclosures required by this guidance shall be provided for fiscal years ending after December 15, 2009. The Company is currently evaluating the impact that the adoption of this guidance will have on the Company's plan asset disclosures.

In December 2008, the Securities and Exchange Commission ("SEC") adopted revisions to its oil and gas disclosure requirements that are intended to align them with current practices and changes in technology. Among other things, the amendments will: replace the single-day year-end pricing assumption with a twelve-month average pricing assumption; permit the disclosure of probable and possible reserves; allow the use of certain technologies to establish reserves; require the disclosure of the qualifications of the technical person primarily responsible for preparing the reserves estimates or conducting a reserves audit; require the filing of the independent reserve engineers' summary report; and permit the disclosure of a reserves sensitivity analysis table to illustrate the impact of different price and/or cost assumptions on reserves. These amendments are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption prohibited. The Company is currently evaluating the impact that the adoption of these amendments will have on the Company's financial position, results of operations, and disclosures. In September 2009, the FASB issued proposed authoritative guidance to align oil and gas reserve estimation and disclosures required for accounting and reporting with the new SEC reserve disclosure requirements discussed above. The proposed guidance would be effective for December 31, 2009 reporting on a prospective basis. Comments on this exposure draft were due in October 2009, with final guidance expected to be issued soon.

In April 2009, the FASB issued authoritative guidance that requires the disclosure of the fair value, together with the carrying amount, of financial instruments, regardless of whether they are recognized at fair value in the statement of financial position, for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance was effective for interim reporting periods ending after June 15, 2009, with earlier adoption permitted for periods ending after March 15, 2009. The Company adopted this guidance for the quarter ended March 31, 2009. As this guidance requires only additional disclosures, there was no impact on the Company's financial position or results of operations as a result of the adoption.

In May 2009, the FASB issued authoritative guidance that provides general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This topic was previously addressed only in auditing literature. This guidance is similar to the existing auditing guidance with some exceptions that are not intended to result in significant changes to practice. Entities are now required to disclose the date through which subsequent events have been evaluated, with such date being the date the financial statements were issued or available to be issued. This guidance was effective on a prospective basis for interim or annual reporting periods ending after June 15, 2009. Accordingly, the Company adopted this guidance for the quarter ended June 30, 2009; however, there was no impact on the Company's financial position or results of operations as a result of the adoption.

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forest Oil Corporation ("Forest") is an independent oil and gas company engaged in the acquisition, exploration, development, and production of natural gas and liquids in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. Unless the context otherwise indicates, references in this quarterly report on Form 10-Q to "Forest," "we," "ours," "us," or like terms refer to Forest Oil Corporation and its subsidiaries.

We currently conduct our operations in three geographical segments and five business units. The geographical segments are: the United States, Canada, and International. The business units are: Western, Eastern, Southern, Canada, and International. We conduct exploration and development activities in each of our geographical segments; however, substantially all of our estimated proved reserves and all of our producing properties are located in North America. Our total estimated proved reserves as of December 31, 2008 were approximately 2,668 Bcfe. At December 31, 2008, approximately 87% of our estimated proved oil and natural gas reserves were in the United States, approximately 11% were in Canada, and approximately 2% were in Italy. Approximately 75% of our estimated proved reserves were natural gas as of December 31, 2008. See Note 12 to the Condensed Consolidated Financial Statements for additional information about our geographical segments.

The following discussion and analysis should be read in conjunction with Forest's Condensed Consolidated Financial Statements and Notes thereto, the information under the headings "Forward-Looking Statements" and "Risk Factors," below, and the information included in Forest's 2008 Annual Report on Form 10-K under the headings "Risk Factors," and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Due to the downturn in the global economy in mid-to-late 2008, demand for oil and natural gas has fallen significantly, resulting in a dramatic decrease in oil and natural gas prices in 2009 as compared to 2008. For example, the average realized price we received for natural gas in the third quarter of 2009 was 65% lower than the price we received in the third quarter of 2008 and the average realized price we received for oil was 44% lower over the same period. As a result of the decreases in commodity prices, our reported earnings and cash flow in 2009 are significantly lower than they were during the same periods in 2008. The decrease in commodity prices also impacted the level of our capital expenditures in 2009 as we intend to keep our full-year exploration and development capital expenditures within our cash flow from operations before changes in working capital. This level of capital expenditure activity is intended to maintain financial flexibility and sufficient liquidity to maintain our assets and operations until margins on oil and gas production improve.

For the third quarter 2009, Forest reported net earnings of $172 million, or $1.53 per basic share, compared to net earnings of $429 million, or $4.77 per basic share, in the third quarter 2008. The decrease was primarily attributable to a significant decline in oil and gas prices, as discussed above, partially offset by a decrease in the deferred tax asset valuation allowance in the third quarter 2009. For the first nine months of 2009, Forest reported a net loss of $968 million, or $9.46 per basic share, compared to net earnings of $356 million, or $3.99 per basic share, during the same period of 2008. The $968 million net loss in the first nine months of 2009 was due primarily to a $1.6 billion non-cash ceiling test write-down recorded in the first quarter of 2009, which was caused by a significant decline in spot natural gas prices during the first quarter of 2009. (See—"Critical Accounting Policies, Estimates, Judgments and Assumptions—Full Cost Method of Accounting" for information on this ceiling test write-down.) Discussion of the components of the changes in our quarterly and year-to-date results follows.

Production volumes, revenues, and average sales prices by product and location for the three and nine months ended September 30, 2009 and 2008 are set forth in the tables below.

Forest's oil and gas production decreased 9% in the third quarter 2009 to 43.8 Bcfe (476 MMcfe per day) compared to 47.9 Bcfe (520 MMcfe per day) in the third quarter 2008. Oil and gas production decreased between the comparable three month periods due primarily to a significant reduction in capital spending in 2009, non-core asset sales, and normal production declines on producing oil and gas properties. Our oil and gas production in the first nine months of 2009 increased 2% to 140.6 Bcfe (515 MMcfe per day) from 137.3 Bcfe (501 MMcfe per day) in the first nine months of 2008. Oil and gas production increased between the comparable nine month periods due to acquisition and drilling activity throughout 2008, which more than offset the significant reduction in capital spending in 2009, non-core asset sales, and normal production declines on producing oil and gas properties.

Forest's oil and natural gas revenues decreased 63% to $177 million in the third quarter 2009 compared to $474 million in the third quarter 2008. The decrease was primarily due to a 59% decrease in the average sales price of oil and gas to $4.05 per Mcfe in the third quarter of 2009 from $9.91 per Mcfe in the third quarter of 2008. For the comparable nine month periods, oil and natural gas revenues decreased 59% to $553 million in 2009 from $1.4 billion in the same period of 2008. The decrease was due to a 60% decrease in the average sales price of oil and gas to $3.94 per Mcfe in 2009 from $9.95 per Mcfe in 2008.

The oil and natural gas revenues and average sales prices reflected in the tables above exclude the effects of commodity derivative instruments since we have elected not to designate our derivative instruments as cash flow hedges. See "Realized and Unrealized Gains and Losses on Derivative Instruments" for more information on gains and losses relating to our commodity derivative instruments.

The table below sets forth the detail of oil and gas production expense for the three and nine months ended September 30, 2009 and 2008.

Lease operating expenses in the third quarter 2009 were $35 million, or $.80 per Mcfe, compared to $45 million, or $.94 per Mcfe, in the third quarter 2008. Lease operating expenses in the first nine months of 2009 were $114 million, or $.81 per Mcfe, compared to $121 million, or $.88 per Mcfe, in the same period of 2008. The decrease in each period was attributable to company-wide cost reduction initiatives and lower service costs.

Production and property taxes, which primarily consist of severance taxes paid on the value of the oil and gas sold, were 6.1% and 5.0% of oil and natural gas revenues for the three months ended September 30, 2009 and 2008, respectively, and 6.2% and 5.0% of oil and natural gas revenues for the nine months ended September 30, 2009 and 2008, respectively. The increase in the percentage in each 2009 period over the corresponding period in 2008 is primarily due to an increase in severance tax rates in Arkansas effective in 2009. In addition, normal fluctuations occur in the percentage between periods based upon the timing of approval of incentive tax credits in Texas and changes in the assessed values of property and equipment for purposes of ad valorem taxes.

The following table summarizes the components of general and administrative expense incurred during the periods indicated.

The decrease in general and administrative expense in each 2009 period compared to the corresponding period in 2008 was primarily due to decreased employee compensation costs and contract labor. The percentage of general and administrative costs capitalized remained relatively consistent between each of the periods presented, ranging from 40% to 41%.

Depreciation, depletion, and amortization expense ("DD&A") in the third quarter 2009 was $65 million, or $1.49 per Mcfe, compared to $137 million, or $2.86 per Mcfe, in the third quarter 2008. For the nine months ended September 30, 2009, DD&A was $238 million, or $1.69 per Mcfe, compared to $379 million, or $2.76 per Mcfe, for the same period in 2008. The per-unit decrease in both periods was primarily due to a $2.4 billion non-cash ceiling test write-down recorded in the fourth quarter 2008 and a $1.6 billion non-cash ceiling test write-down recorded in the first quarter 2009.

In the first quarter 2009, we recorded a non-cash ceiling test write-down for both our United States and Canadian cost centers pursuant to the ceiling test limitation prescribed by the Securities and Exchange Commission ("SEC") for companies using the full cost method of accounting. The combined write-down totaled $1.6 billion and was primarily a result of a significant decline in natural gas prices in the first quarter of 2009. See—"Critical Accounting Policies, Estimates, Judgments and Assumptions—Full Cost Method of Accounting" and Part II, Item 1A,—"Risk Factors—Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values."

The following table summarizes interest expense incurred during the periods indicated.

The increase in interest expense in the 2009 periods compared to the corresponding three and nine month periods in 2008 was primarily attributable to an increase in debt levels related to the acquisition of oil and gas assets from Cordillera Texas, L.P. on September 30, 2008. Interest expense also increased between the comparable three and nine month periods due to a decrease in interest costs capitalized as a result of a decrease in the amount of unproved properties under development. Interest costs related to significant unproved properties that are under development are capitalized to oil and gas properties.

The table below sets forth realized and unrealized gains and losses on derivatives recognized under "Costs, expenses, and other" in our Condensed Consolidated Statements of Operations for the periods indicated. See Note 8 and Note 9 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.

The table below sets forth the components of "Other, net" within "Costs, expenses, and other" of the Condensed Consolidated Statements of Operations for the periods indicated.

Unrealized foreign currency exchange gains and losses in the table above relate to the outstanding intercompany indebtedness, which is denominated in U.S. dollars, between Forest Oil Corporation and our wholly-owned Canadian subsidiary.

The unrealized losses on other investments in the table above relate to fair value adjustments to the shares of Pacific Energy Resources, Ltd. ("PERL") common stock and the zero coupon senior subordinated note from PERL due 2014, which were received as a portion of the total consideration for the sale of our Alaska assets in August 2007. In March 2009, PERL filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. PERL has indicated that the value of its assets is less than the amount of its senior unsubordinated debt. Based on these facts and circumstances, we estimated the fair value of the PERL common stock and note to be zero as of September 30, 2009. See Note 8 to the Condensed Consolidated Financial Statements for more information on these investments.

Our effective income tax rate was (1,937)% and 35% of earnings before taxes for the three months ended September 30, 2009 and 2008, respectively. For each of the nine month periods ended September 30, 2009 and 2008, our effective income tax rate was 35% of earnings before taxes. The significant change in our effective tax rate in the third quarter of 2009 as compared to the third quarter of 2008 is primarily due to a reversal of the remaining valuation allowance that was placed on our deferred tax assets in the United States during the first quarter of 2009. See Note 10 to the Condensed Consolidated Financial Statements and—"Critical Accounting Policies, Estimates, Judgments, and Assumptions—Valuation of Deferred Tax Assets" for more information on our income taxes and valuation allowance.

Our exploration, development, and acquisition activities require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facilities as our primary sources of liquidity. To fund large and other exceptional transactions, such as acquisitions and debt refinancing transactions, we have looked to the private and public capital markets as another source of financing and, as market conditions have permitted, we have engaged in asset monetization transactions.

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. Natural gas accounted for approximately 75% of our total oil and gas production for the three and nine months ended September 30, 2009 and, as a result, our operations and cash flow are more sensitive to fluctuations in the market price for natural gas than to fluctuations in the market price for oil. We employ a commodity hedging strategy as an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of October 31, 2009, we had hedged, via commodity swaps and collar instruments, approximately 97 Bcfe of our total 2009 production and 69 Bcfe of our total 2010 production. This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production in 2009 and 2010. However, these hedging activities are inherently risky and may result in reduced income or even financial losses to us. See Part II, Item 1A,—"Risk Factors—Our use of hedging transactions could result in financial losses or reduce our income," for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions. As of October 31, 2009, all of our derivatives counterparties are commercial banks that are parties to our credit facilities, or their affiliates, with the exception of one counterparty with whom we hold three basis swaps. For further information concerning our derivative contracts, see Item 3—"Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk" below.

The other primary source of liquidity is our U.S. credit facility and our Canadian credit facility, which had an aggregate borrowing base of $1.62 billion as of September 30, 2009. These facilities are

used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facilities are secured by a portion of our assets and mature in June 2012. We had $1.2 billion available under these facilities as of September 30, 2009. See the heading "Bank Credit Facilities" below for further details.

The public and private capital markets have served as our primary source of financing to fund large acquisitions and other exceptional transactions. In the past, we have issued debt and equity in both the public and private capital markets. For example, in February 2009, we issued $600 million principal amount of 8¹/2% senior notes due 2014 in a private offering and in May 2009, we issued approximately 14 million shares of common stock. Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the domestic and global financial markets, the credit ratings assigned to our debt by independent credit rating agencies, our operational and financial performance, the value and performance of our equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

We also have engaged in asset dispositions as a means of generating additional cash to fund expenditures and enhance our financial flexibility. For example, during 2008, we sold certain non-core assets for total proceeds of $310 million and we have sold assets for $146 million during the first nine months of 2009. In October 2009, we entered into a definitive agreement to sell certain non-core assets in Canada for approximately $58 million. We plan to sell additional non-core oil and gas assets; however, due to current economic conditions, we are not certain of the timing of these sales. As divestitures are completed, we intend to use the proceeds to reduce debt.

We believe that our cash flow provided by operating activities and funds available under our credit facilities will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures, and our contractual obligations for the foreseeable future. However, if our revenue and cash flow decrease in the future as a result of further deterioration in domestic and global economic conditions or a decline in commodity prices, we may have to reduce our spending levels. We believe that this financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions deteriorate. See Part I, Item 1A,—"Risk Factors," of our 2008 Annual Report on Form 10-K and Part II, Item 1A,—"Risk Factors," of this report.

Our bank credit facilities consist of a $1.65 billion U.S. credit facility (the "U.S. Facility") with a syndicate of banks led by JPMorgan Chase Bank, N.A., and a $150 million Canadian credit facility (the "Canadian Facility," and together with the U.S. Facility, the "Credit Facilities") with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Credit Facilities will mature in June 2012. Our availability under the Credit Facilities is governed by a borrowing base (the "Global Borrowing Base"). The determination of the Global Borrowing Base is made by the lenders in their sole discretion taking into consideration the estimated value of our oil and gas properties in accordance with the lenders' customary practices for oil and gas loans. The Global Borrowing Base is redetermined semi-annually and the available borrowing amount could be increased or decreased as a result of such redeterminations. In October 2009, our bank group reaffirmed our $1.62 billion Global Borrowing Base. The next redetermination of the borrowing base is expected to occur in the second quarter of 2010. In addition to the semi-annual redeterminations, Forest and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the Global Borrowing Base redetermined. Because the process for determining the Global Borrowing Base involves evaluating the estimated value of our oil and gas properties using pricing models determined by the lenders at that time, a decline in oil and gas commodity prices could result in a determination to decrease the Global Borrowing Base in the future.

The Global Borrowing Base is also subject to change in the event (i) we issue senior notes, in which case the Global Borrowing Base will immediately be reduced by an amount equal to $0.30 for every $1.00 principal amount of any newly issued senior notes, excluding any senior notes that we may issue to refinance senior notes that were outstanding on May 9, 2008, or (ii) if we sell oil and natural gas properties included in the calculation of the Global Borrowing Base having a fair market value in excess of 10% of the Global Borrowing Base then in effect. The Global Borrowing Base is subject to other automatic adjustments under the facilities. As a result of issuing $600 million of 8¹/2% senior notes due 2014 in February 2009, our borrowing base was lowered from $1.8 billion to $1.62 billion effective February 17, 2009. As a result of the adjustment to the Global Borrowing Base, we reallocated amounts under the U.S. Facility and Canadian Facility and currently have allocated $1.47 billion to the U.S. Facility and $150 million to the Canadian Facility. A lowering of the Global Borrowing Base could require us to repay indebtedness in excess of the Global Borrowing Base in order to cover the deficiency. The automatic lowering of the Global Borrowing Base on February 17, 2009 did not result in any deficiency, and therefore we were not required to repay any amounts.

Borrowings under the U.S. Facility bear interest at one of two rates as may be elected by us. Borrowings bear interest at:

Borrowings under the Canadian Facility bear interest at one of three rates as may be elected by us. Borrowings bear interest at a rate that may be based on:

The Credit Facilities include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also include financial covenants. For example, the Credit Facilities provide that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) to be greater than (i) 4.50 to 1.00 for four consecutive fiscal quarters ending in 2009 and 2010; (ii) 4.00 to 1.00 for four consecutive fiscal quarters ending in 2011; and (iii) 3.50 to 1.00 at any time thereafter. Since commodity prices significantly impact the level of our earnings and therefore EBITDA, if commodity prices are not at sufficient levels in future periods, we may not be in compliance with this or other financial covenants. If we were to fail to perform our obligations under these covenants or other covenants and obligations, it could cause an event of default and the Credit Facilities could be terminated and amounts outstanding could be declared immediately due and payable by the lenders, subject to notice and cure periods in certain cases. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, a failure of the liens securing the Credit Facilities, and an event of default under the Canadian Facility. In addition, bankruptcy and insolvency events with respect to Forest or certain of its

subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facilities. An acceleration of our indebtedness under the Credit Facilities could in turn result in an event of default under the indentures for our senior notes, which in turn could result in the acceleration of the senior notes. For example, the indentures for our 8% senior notes due 2011 and our 7³/4% senior notes due 2014 include as events of default, among others, a default on indebtedness that results in the acceleration of indebtedness in an amount greater than $10 million; each of the indentures for our 8¹/2% senior notes due 2014 and our 7¹/4% senior notes due 2019 include a similar event of default if the amount involved is greater than $25 million.

The Credit Facilities are collateralized by a portion of our assets. We are required to mortgage and grant a security interest in the greater of 75% of the present value of our consolidated proved oil and gas properties, or 1.875 multiplied by the allocated U.S. borrowing base. We also are required to and have pledged the stock of several subsidiaries to the lenders to secure the Credit Facilities. Under certain circumstances, we could be obligated to pledge additional assets as collateral. If our corporate credit ratings assigned by Moody's and S&P improve and meet pre-established levels, the collateral requirements would cease to apply and, at our request, the banks would release their liens and security interests on our properties. In addition to these collateral requirements, one of our subsidiaries, Forest Oil Permian Corporation, is a subsidiary guarantor of the Credit Facilities.

The lending group under our U.S. Facility includes the following institutions: JPMorgan Chase Bank, N.A. ("JPMorgan Chase"), Bank of America, N.A. ("Bank of America"), Citibank, N.A., BNP Paribas, BMO Capital Markets Financing, Inc. ("BMO"), Credit Suisse, Cayman Islands Branch ("Credit Suisse"), Deutsche Bank AG New York Branch ("Deutsche Bank"), U.S. Bank National Association, The Bank of Nova Scotia ("Bank of Nova Scotia"), Fortis Capital Corp. ("Fortis"), Bank of Scotland, ABN Amro Bank N.V. ("ABN Amro"), UBS Loan Finance LLC, Compass Bank, Wells Fargo Bank, N.A. ("Wells Fargo"), Mizuho Corporate Bank, Ltd., Toronto Dominion (Texas) LLC, Barclays Bank PLC ("Barclays"), Bank of Oklahoma, N.A., Export Development Canada, Guaranty Bank and Trust Company, and Union Bank of California, N.A. The lenders under our Canadian Facility include: JPMorgan Chase Bank, N.A., Toronto Branch ("JPM Toronto", with JPMorgan Chase, collectively "JPMorgan"), Bank of Montreal, The Toronto-Dominion Bank (together with Toronto Dominion (Texas) LLC, "Toronto Dominion"), Bank of America, N.A., Canada Branch, and Citibank, N.A., Canadian Branch. Of the $1.8 billion total nominal amount under the Credit Facilities, JPMorgan, Bank of America, BNP Paribas, Credit Suisse, Deutsche Bank, Bank of Nova Scotia, Toronto Dominion, and Wells Fargo hold approximately 62% of the total commitments, with each of these eight lenders holding an equal share. With respect to the other 38% of the total commitments, no single lender holds more than 4.2% of the total commitments.

From time to time, we engage in other transactions with a number of the lenders under the Credit Facilities. Such lenders or their affiliates may serve as underwriters or initial purchasers of our debt and equity securities, act as agent or directly purchase our production, or serve as counterparties to our commodity and interest rate derivative agreements. As of October 31, 2009, our primary derivative counterparties included the following lenders and their affiliates: ABN Amro, BMO, BNP Paribas, Barclays, Credit Suisse, Compass Bank, Deutsche Bank, Fortis, Bank of Nova Scotia, Toronto Dominion, Bank of America, U.S. Bank National Association, and Wells Fargo. As of October 31, 2009, our derivative transactions with BMO, Credit Suisse, Bank of Nova Scotia, BNP Paribas, and Toronto Dominion accounted for approximately 74 Bcfe, or 76% of our 2009 hedged production, and 49 Bcfe, or 71% of our 2010 hedged production. Our obligations under our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our Credit Facilities. See Item 3—"Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk," below for additional details concerning our derivative arrangements.

At September 30, 2009, there were outstanding borrowings of $318 million under the U.S. Facility at a weighted average interest rate of 1.31%, and there were outstanding borrowings of $135 million

under the Canadian Facility at a weighted average interest rate of 1.96%. We also had used the Credit Facilities for $8 million in letters of credit, resulting in availability under the Credit Facilities of $1.2 billion at September 30, 2009. At October 30, 2009, there were outstanding borrowings of $290 million under the U.S. Facility at a weighted average interest rate of 1.25%, and there were outstanding borrowings of $128 million under the Canadian Facility at a weighted average interest rate of 1.71%. We also had used the Credit Facilities for $8 million in letters of credit, resulting in availability under the Credit Facilities of $1.2 billion at October 30, 2009.

Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody's Investor Services and Standard & Poor's Rating Services currently rate each series of our senior notes and, in addition, they have assigned us a general credit rating. Our Credit Facilities include provisions that are linked to our credit ratings. For example, our collateral requirements will vary based on our credit ratings; however, we do not have any credit rating triggers that would accelerate the maturity of amounts due under credit facilities or the debt issued under the indentures for our senior notes. The indentures for our senior notes also include terms linked to our credit ratings. These terms allow us greater flexibility if our credit ratings improve to investment grade and other tests have been satisfied, in which event we would not be obligated to comply with certain restrictive covenants included in the indentures. Our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Net cash provided by operating activities, net cash used by investing activities, and net cash (used) provided by financing activities for the nine months ended September 30, 2009 and 2008 were as follows:

Cash flows provided by operating activities are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. The decrease in net cash provided by operating activities in the nine months ended September 30, 2009 compared to the same period of 2008 was primarily due to lower commodity prices partially offset by a decreased investment in net operating assets in 2009 as compared to 2008.

Cash flows used by investing activities are primarily comprised of the acquisition, exploration, and development of oil and gas properties net of dispositions of oil and gas properties. The decrease in net cash used by investing activities in the nine months ended September 30, 2009 compared to the same period of 2008 was primarily due to a decrease in the cash used for the acquisition of oil and gas properties and in capital spending. See "Capital Expenditures" below. Cash paid for exploration, development, and acquisition costs as reflected in the Condensed Consolidated Statements of Cash Flows differs from the reported capital expenditures in the table below due to the timing of when the capital expenditures are incurred and when the actual cash payment is made.

Net cash used by financing activities in the nine months ended September 30, 2009 included net repayments of bank borrowings of $850 million, partially offset by net proceeds of $560 million for the issuance of 8¹/2% senior notes and net proceeds of $256 million for the issuance of common stock. Net cash provided by financing activities in the nine months ended September 30, 2008 included net bank proceeds of $934 million as well as net proceeds of $247 million for the issuance of 7¹/4% senior notes, which was offset by the redemption of the 8% senior notes for $265 million.

Expenditures for property acquisitions, exploration, and development were as follows:

Due to significant changes in the overall economy as well as the price for oil and natural gas, we have chosen to significantly reduce our capital expenditures and drilling activity in 2009 compared with 2008. We have established a capital budget of approximately $500 million to $600 million for the year ending December 31, 2009.

Reference should be made to our 2008 Annual Report on Form 10-K under Item 7.—"Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions" for a discussion of other critical accounting policies in addition to those discussed below.

The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the full cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in financial statements. We have elected to follow the full cost method, which is described below.

Under the full cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded. Capitalized costs applicable to each full cost center are depleted using the units of production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for prospectively in the depletion calculations.

Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool, or reported as impairment expense in the Condensed Consolidated Statements of Operations, as applicable.

Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed each quarter on a country-by-country basis. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves. This ceiling is compared to the net book value of the oil and gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is required. Forest recorded a $1.6 billion non-cash ceiling test write-down in the first quarter of 2009 based on the March 31, 2009 NYMEX spot prices for natural gas and oil of $3.63 per MMBtu and $49.66 per barrel, respectively. At September 30, 2009, the spot prices for natural gas and oil were $3.30 per MMBtu and $70.61 per barrel, respectively. Based on these prices, a write-down was not necessary in the third quarter of 2009. Under the SEC's new rules, which are effective for fiscal years ending on or after December 31, 2009, the ceiling limit will be calculated based on twelve-month average pricing rather than period-end spot pricing.

In countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. An impairment of unproved property costs may be indicated through evaluation of drilling results, relinquishment of drilling rights, or other information.

Under the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments are also assessed on a property-by-property basis and are charged to expense when assessed.

The full cost method is used to account for our oil and gas exploration and development activities, because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.

We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are generally determined based on differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on income tax assets and liabilities of a change in tax rates is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.

In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as future taxable income is sufficient to utilize net operating and other credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive. Negative evidence considered by management primarily included a recent history of book losses driven in large part from ceiling test write-downs. Positive evidence considered by management included forecasted book income over a reasonable period of time and the fact that our net operating loss carryforwards do not begin to expire until after 2017. Based upon the evaluation of what management determined to be relevant evidence, we have recorded a net deferred tax asset attributable to the U.S. of approximately $328 million. See Note 10 to the Condensed Consolidated Financial Statements.

The primary evidence utilized to determine that it is more likely than not that a portion of the deferred tax asset will be realized was management's expectation of future book income over the next several years, despite the negative evidence of recent book losses caused by ceiling test write-downs in both the fourth quarter of 2008 and the first quarter of 2009. These ceiling test write-downs, which are not considered a fair value impairment test, have dramatically reduced our prospective depletion rate, making future book income more likely than would be the case had these ceiling test write-downs not occurred. Despite a lower expected depletion rate, our projection of future book income is most contingent on projected oil and gas prices, which are based on quoted NYMEX oil and gas futures. Accordingly, our evaluation of the amount of the deferred tax asset more likely than not to be realizable will likely change in future periods as estimates of our future income change due to changes in expected future oil and gas prices and other factors, and these changes could be material. For example, from June 30, 2009 to September 30, 2009, due primarily to an increase in expected realized natural gas prices, our projection of future book income increased substantially and we reduced the valuation allowance recorded against our deferred income tax assets by $164 million. If the forecasted price assumed for oil and natural gas had been 10% lower than what was utilized for our projected future book income, we would have recorded a valuation allowance of approximately $65 million as of September 30, 2009.

The information in this Quarterly Report on Form 10-Q including "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 2 of Part I of this report, contains "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. Forward-looking statements are statements, other than statements of historical or present facts, that address activities, events, outcomes, and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate, or anticipate (and other similar expressions) will, should, or may occur in the future. Generally, the words "expects," "anticipates," "targets," "goals," "projects," "intends," "plans," "believes," "seeks,"

"estimates," "continue," "may," "will," "should," "would," "potential," variations of such words, and similar expressions identify forward-looking statements, and any statements regarding our future financial condition, results of operations, and business are also forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward-looking statements appear in a number of places in this report and include statements with respect to, among other things:

We believe the expectations and forecasts reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements can be affected by inaccurate assumptions and are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil and gas, including such risks that are specific to our operations and outlook. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included in Part I of our 2008 Annual Report on Form 10-K and the risks described in Part II, Item 1A,—"Risk Factors", in this report. These risks include, but are not limited to, the following:

In addition, we may be subject to currently unforeseen risks that may have a materially adverse impact on us and our operations. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. Should one or more of the risks or uncertainties, including those described above or elsewhere in this Form 10-Q, in our 2008 Annual Report on Form 10-K, or in our other filings with the Securities and Exchange Commission occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information to reflect events or circumstances after the filing of this report with the SEC, except as required by law. All forward-looking statements, expressed or implied, included in this Form 10-Q and attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or that persons acting on our behalf may issue.

We are exposed to market risk, including the effects of adverse changes in commodity prices, interest rates, and foreign currency exchange rates as discussed below.

We produce and sell natural gas, crude oil, and natural gas liquids for our own account in the United States and Canada. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. In order to reduce the impact of fluctuations in commodity prices, or to protect the economics of property acquisitions, we make use of an oil and gas

hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other financial instruments with counterparties who, in general, are participants in our credit facilities. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.

In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we attempt to fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of September 30, 2009, we had entered into the following swaps:

Subsequent to September 30, 2009, through October 31, 2009, we entered into additional gas swaps covering 50 Bbtu per day for November and December 2009 at a weighted average hedged price per MMBtu of $5.43 and an additional oil swap covering 500 barrels per day for Calendar 2010 at a hedged price per Bbl of $80.00.

We also enter into costless collar agreements with third parties. A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price. As of September 30, 2009, we had entered into the following collars:

Subsequent to September 30, 2009, through October 31, 2009, we entered into an additional oil collar covering 1,000 barrels per day for Calendar 2010 at a hedged floor and ceiling price per Bbl of $60.00 and $100.00, respectively.

We also use basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the index price at which the natural gas production is sold. As of September 30, 2009, we had entered into the following basis swaps:

The fair value of all our commodity derivative instruments based on various inputs, including published forward prices, at September 30, 2009 was a net asset of approximately $34.6 million.

We periodically enter into interest rate derivative agreements in an attempt to normalize the mix of fixed and floating interest rates within our debt portfolio. The table below sets forth our outstanding fixed-to-floating interest rate swaps as of September 30, 2009.

Subsequent to September 30, 2009, through October 31, 2009, we entered into an additional interest rate swap as set forth in the table below.

In addition to the interest rate swaps, during the nine months ended September 30, 2009, we entered into certain interest rate swaptions, which enable the counterparties to exercise options to enter into interest rate swaps with us in exchange for a premium paid to us. The premiums received on these swaptions are amortized as realized gains on derivatives over the term of the related swaption. We entered into these interest rate swaptions because our targeted floating interest rates were not attainable at that time in the interest rate swap market yet premiums were available from counterparties for the option to swap our 8.5% fixed rate for the floating rates we had targeted. The table below sets forth our outstanding interest rate swaption as of September 30, 2009.

Subsequent to September 30, 2009, the swaption above expired unexercised and, through October 31, 2009, we entered into an additional interest rate swaption as set forth in the table below.

The fair value of all our interest rate derivative instruments based on various inputs, including published forward rates, at September 30, 2009 was a net asset of approximately $3.2 million.

The table below sets forth the changes that occurred in the fair values of our open derivative contracts during the nine months ended September 30, 2009, beginning with the fair value of our derivative contracts on December 31, 2008. Due to the volatility of oil and natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Actual gains and losses recognized related to our commodity derivative instruments will likely differ from those estimated at September 30, 2009 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

The following table presents principal amounts and related interest rates by year of maturity for our debt obligations at September 30, 2009.

We conduct business in several foreign currencies and thus are subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing, and investing transactions. We have not entered into any foreign currency forward contracts or other similar financial instruments to manage this risk. Expenditures incurred relative to the foreign concessions held by Forest outside of North America have been primarily United States dollar-denominated, as have cash proceeds related to property sales and farmout arrangements. Substantially all of our Canadian revenues and costs are denominated in Canadian dollars. While the value of the Canadian dollar does fluctuate in relation to the U.S. dollar, we believe that any currency risk associated with our Canadian operations would not have a material impact on our results of operations.

We have established disclosure controls and procedures to ensure that material information relating to Forest and its consolidated subsidiaries is made known to the Officers who certify Forest's financial reports and the Board of Directors.

Our Chief Executive Officer, H. Craig Clark, and our Chief Financial Officer, David H. Keyte, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a—15(e) and 15d—15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of the end of the quarterly period ended September 30, 2009 (the "Evaluation Date"). Based on this evaluation, they believe that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms; and (ii) is accumulated and communicated to Forest's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

The following risk factors update the Risk Factors included in our Annual Report on Form 10-K for fiscal year ended December 31, 2008 ("Annual Report"). Except as set forth below and as previously disclosed in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2009 and June 30, 2009, there have been no material changes to the risks described in Part I, Item 1A, of our Annual Report.

We have substantial indebtedness and may incur more debt in the future. Our leverage may materially affect our operations and financial condition.

As of October 30, 2009, the principal amount of our outstanding consolidated debt was approximately $2.5 billion, which amount included approximately $418 million outstanding under our combined U.S. and Canadian credit facilities. Our level of indebtedness has several important effects on our business and operations; among other things, it may:

We may incur more debt in the future. In February 2009, for example, we issued $600 million of 8¹/2% senior notes due 2014. The net proceeds from this offering were used to repay a portion of the outstanding borrowings under our U.S. credit facility.

Our credit and debt agreements contain various restrictive covenants. A failure on our part to comply with the financial and other restrictive covenants contained in our bank credit facilities and the indentures pertaining to our outstanding senior notes could result in a default under these agreements. Any default under our bank credit facilities or indentures could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future. See Part I, Item 2,—"Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facilities" for a discussion of certain financial covenants under our bank credit facilities. In addition, the global borrowing base included in our bank credit facilities is subject to periodic redetermination by our lenders. A lowering of our global borrowing base could require us to repay indebtedness in excess of the borrowing base. The next redetermination of the borrowing base is expected to occur in the second quarter of 2010.

Higher levels of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be affected by oil and natural gas prices, financial, business, domestic and global economic conditions, governmental regulations (including environmental regulations), and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

Our use of hedging transactions could result in financial losses or reduce our income.

To reduce our exposure to fluctuations in oil and natural gas prices, we have entered into and expect in the future to enter into derivative instruments (or hedging agreements) for a portion of our oil and natural gas production. Our commodity hedging agreements are limited in duration, usually for periods of two years or less; however, in conjunction with acquisitions, we sometimes enter into or acquire hedges for longer periods. As of October 31, 2009, we had hedged, via commodity swaps and collar instruments, approximately 97 Bcfe of our total 2009 production and 69 Bcfe of our total 2010 production. Our hedging transactions expose us to certain risks and financial losses, including, among others:

Our hedging transactions will impact our earnings in various ways. Due to the volatility of oil and natural gas prices, we may be required to recognize gains and losses on derivative instruments as the estimated fair value of our commodity derivative instruments is subject to significant fluctuations from period to period. The amount of any actual realized gains or losses recognized will likely differ from our period to period estimates and will be a function of the actual price of the commodities on the settlement date of the derivative instrument. We expect that commodity prices will continue to fluctuate in the future and, as a result, our periodic financial results will continue to be subject to fluctuations related to our derivative instruments.

Currently, all of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our bank credit facilities, with the exception of one counterparty with whom we hold three basis swaps. As of October 31, 2009, our primary derivative counterparties included the following lenders and their affiliates: ABN Amro Bank N.V., BMO Capital Markets Financing, Inc. ("BMO"), BNP Paribas, Barclays Bank PLC, Credit Suisse, Cayman Islands Branch ("Credit Suisse"), Compass Bank, Deutsche Bank AG New York Branch, Fortis Capital Corp., The Bank of Nova Scotia, Toronto Dominion (Texas) LLC and The Toronto-Dominion Bank (collectively, "Toronto Dominion"), Bank of America, N.A., U.S. Bank National Association, and Wells Fargo Bank, N.A.. As of October 31, 2009, our derivative transactions with BMO, Credit Suisse, The Bank of Nova Scotia, BNP Paribas, and Toronto Dominion accounted for approximately 74 Bcfe, or 76% of our 2009 hedged production, and 49 Bcfe, or 71% of our 2010 hedged production. Our obligations under our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our bank credit facilities.

Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting to report our oil and gas operations. Under this method, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and gas properties may not exceed a "ceiling limit," which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling test write-down." Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down would not impact cash flow from operating activities, but it would reduce our shareholders' equity. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions—Full Cost Method of Accounting" above, for further details.

Investments in unproved properties, including capitalized interest costs, are also assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized, or is reported as a period expense, as appropriate. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the amount by which the ceiling limit exceeds the capitalized costs of proved oil and gas properties would be reduced.

We also assess the carrying amount of goodwill in the second quarter of each year and at other periods when events occur that may indicate an impairment exists. These events include, for example, a significant decline in oil and gas prices or a decline in our market capitalization.

The risk that we will be required to write-down the carrying value of our oil and gas properties, our unproved properties, or goodwill increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. For example, oil and natural gas prices declined significantly during the second half of 2008. At December 31, 2008, the spot prices for oil and natural gas were $44.60 per barrel and $5.71 per MMBtu, respectively. Based on these prices, we recorded a non-cash ceiling test write-down of $2.4 billion for the three months and year ended December 31, 2008. At March 31, 2009, the spot prices for oil and natural gas were $49.66 per barrel and $3.63 per MMBtu, respectively. Based on these prices, we recorded an additional non-cash ceiling test write-down of $1.6 billion for the three months ended March 31, 2009. The write-downs are reflected as a charge to net earnings. At September 30, 2009, the spot prices for oil and natural gas were $70.61 per barrel and $3.30 per MMBtu, respectively. Based on these prices, a ceiling test write-down was not necessary. However, additional ceiling test write-downs of the full cost pools in the United States and Canada may be required if oil and natural gas prices decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in the respective full cost pools exceed the discounted future net cash flows from the additional reserves, if any, attributable to each of the cost pools.

Our oil and gas operations are subject to various environmental and other governmental laws and regulations that materially affect our operations.

Our oil and gas operations are subject to various U.S. federal, state, and local laws and regulations, Canadian federal, provincial, and local laws and regulations, and local and federal laws and regulations in Italy and South Africa. These laws and regulations may be changed in response to

economic or political conditions. Matters subject to current governmental regulation and/or pending legislative or regulatory changes include the discharge or other release into the environment of wastes and other substances in connection with drilling and production activities (including fracture stimulation operations), bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning our operations, the spacing of wells, unitization and pooling of properties, taxation, and the use of derivative hedging instruments. Failure to comply with the laws and regulations in effect from time to time may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that could delay, limit, or prohibit certain of our operations. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies may restrict the rates of flow of oil and gas wells below actual production capacity. Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. The laws in the United States, Canada, Italy, and South Africa regulate, among other things, the production, handling, storage, transportation, and disposal of oil and gas, by-products from oil and gas, and other substances and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. We may not be able to recover some or any of these costs from insurance.

Canada and Italy are signatories to the United Nations Framework Convention on Climate Change and have ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other greenhouse gases ("GHG"). In response to the Kyoto Protocol, the Canadian federal government introduced the Regulatory Framework for Air Emissions (the "Regulatory Framework") for regulating GHG emissions by establishing mandatory emissions reduction requirements on a sector basis. Sector-specific regulations are expected to come into force in 2010, but the Regulatory Framework is expected to allow emissions trading, which would enable regulated sources of GHG emissions to purchase emissions allowances or emission reduction credits from other sources. Similar GHG emission reduction requirements apply to our operations in Italy. Additionally, GHG regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specified gas emissions, relative to gross domestic product, to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020 and which imposes duties to report. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets. The Canadian federal government proposes to enter into equivalency agreements with provinces that establish a regulatory regime to ensure consistency with the federal plan. The success of any such plan appears to be doubtful in the current political climate, leaving multiple overlapping levels of regulation. The direct and indirect costs of these regulations may adversely affect our operations and financial results.

In addition, the U.S. House of Representatives has recently passed a bill—the "American Clean Energy and Security Act of 2009," also known as the "Waxman-Markey cap-and-trade legislation" or ACESA—to control and reduce the emission of GHGs in the United States through the grant of emission allowances which would gradually be decreased over time, and the Senate is considering similar legislation. Moreover, nearly half of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, the U.S. Supreme Court's holding in its 2007 decision, Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an "air pollutant" under the federal Clean Air Act, could result in future regulation of GHG emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of GHGs. In late September and early October of 2009, the United States Environmental Protection Agency ("EPA") officially proposed two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which would regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources such as power plants or industrial facilities. EPA indicated that it hopes to adopt final versions of both sets of rules by March 2010. While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the United States to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.

We may face liabilities related to the pending bankruptcy of Pacific Energy Resources, Ltd.

In August 2007, we closed on the sale of our oil and gas assets in Alaska (the "Alaska Assets") to Pacific Energy Resources, Ltd. ("PERL"). In March 2009, PERL filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. PERL requested, and the bankruptcy court has approved, abandonment of PERL's interests in the Alaska Assets. The remaining working interest owners in the Alaska Assets previously made the assertion that, in its role as the assignor to PERL, Forest should be held liable for any contractual obligations of PERL with respect to the Alaska Assets, including obligations related to operating costs for the Alaska Assets and for costs associated with the final plugging and decommissioning of wells and production facilities. Forest disagrees with the working interest owners' assertion and, to the extent necessary, will vigorously oppose any efforts to hold Forest liable for PERL's unsatisfied obligations. We cannot predict, however, whether we would be successful in avoiding liabilities associated with PERL's unsatisfied obligations.

There were no sales of unregistered equity securities during the period covered by this report.

The table below sets forth information regarding repurchases of our common stock during the third quarter 2009. The shares repurchased represent shares of our common stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of shares of

restricted stock and phantom stock units that are settled in shares. Forest does not consider this a share buyback program.

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

Swap Term		Notional Amount (In Thousands)			Floating Rate		Fixed Rate

October 2009 - May 2014		$	100,000		3 month LIBOR + 5.00%			7.75	%

Option Term		Swap Term		Premium Received (In Thousands)			Notional Amount (In Thousands)			Floating Rate		Fixed Rate

Jul 2009 - Oct 2009		Oct 2009 - Feb 2014		$	745		$	100,000		1 month LIBOR + 5.60%			8.50	%

Option Term		Swap Term		Premium Received (In Thousands)			Notional Amount (In Thousands)			Floating Rate		Fixed Rate

Oct 2009 - Jan 2010		Jan 2010 - Feb 2014		$	550		$	100,000		1 month LIBOR + 5.73%			8.50	%

		Three Months Ended September 30,						Nine Months Ended September 30,

		2009			2008			2009			2008
		(In Thousands)
Commodity derivatives:
	Realized (gains) losses	$	(81,395	)		48,842			(237,503	)		109,798
	Unrealized losses (gains)		87,857			(498,182	)		135,472			(31,608	)
Interest rate derivatives:
	Realized (gains) losses		(3,508	)		—			(6,925	)		889
	Unrealized gains		(8,619	)		—			(3,256	)		(4,721	)

Realized and unrealized (gains) losses on derivative instruments, net		$	(5,665	)		(449,340	)		(112,212	)		74,358

	Three Months Ended September 30,						Nine Months Ended September 30,

	2009			2008			2009			2008
	(In Thousands)
Federal income tax at 35% of earnings (loss) before income taxes	$	2,961			232,032			(520,983	)		193,097
Change in valuation allowance for deferred tax assets		(163,858	)		—			(701	)		—
State income taxes, net of federal income tax benefits		(538	)		8,363			(15,195	)		6,075
Effect of differing tax rates in Canada		(374	)		(1,250	)		11,501			(4,349	)
Effect of federal, state, and foreign tax on permanent items		(848	)		1,138			1,295			966
Adjustments for statutory rate reductions and other		(1,194	)		(6,341	)		3,882			(341	)

Total income tax	$	(163,851	)		233,942			(520,201	)		195,448

		Oil and Gas Operations

		Three Months Ended September 30, 2009									Nine Months Ended September 30, 2009
		United States		Canada		International			Total Company		United States			Canada			International			Total Company
		(In Thousands)
Oil and gas sales		$	151,239		25,945		—			177,184		471,787			81,686			—			553,473
Costs and expenses:
	Lease operating expenses		28,334		6,604		—			34,938		93,202			21,003			—			114,205
	Production and property taxes		9,969		904		—			10,873		31,887			2,472			—			34,359
	Transportation and processing costs		3,334		2,018		—			5,352		9,719			6,199			—			15,918
	Depletion		48,050		14,067		—			62,117		186,592			42,758			—			229,350
	Ceiling test write-down of oil and gas properties		—		—		—			—		1,376,822			199,021			—			1,575,843
	Accretion of asset retirement obligations		1,737		253		24			2,014		5,397			727			71			6,195

Segment earnings (loss)		$	59,815		2,099		(24	)		61,890		(1,231,832	)		(190,494	)		(71	)		(1,422,397	)

Capital expenditures⁽¹⁾		$	69,207		13,775		3,366			86,348		379,765			46,567			5,603			431,935

Goodwill⁽²⁾		$	239,420		16,184		—			255,604		239,420			16,184			—			255,604

		Oil and Gas Operations

		Three Months Ended September 30, 2008									Nine Months Ended September 30, 2008
		United States		Canada		International			Total Company		United States		Canada		International			Total Company
		(In Thousands)
Oil and gas sales		$	406,484		67,753		—			474,237		1,155,818		210,084		—			1,365,902
Costs and expenses:
	Lease operating expenses		35,488		9,424		—			44,912		93,534		27,356		—			120,890
	Production and property taxes		22,524		958		—			23,482		64,995		2,686		—			67,681
	Transportation and processing costs		2,545		2,329		—			4,874		7,240		7,200		—			14,440
	Depletion		112,233		22,249		—			134,482		305,660		67,204		—			372,864
	Accretion of asset retirement obligations		1,579		271		21			1,871		4,678		882		62			5,622

Segment earnings (loss)		$	232,115		32,522		(21	)		264,616		679,711		104,756		(62	)		784,405

Capital expenditures⁽¹⁾		$	1,411,927		55,758		1,483			1,469,168		2,175,261		158,473		4,057			2,337,791

Goodwill⁽²⁾		$	248,805		16,283		—			265,088		248,805		16,283		—			265,088

	Three Months Ended September 30, 2008

	(In Thousands)
Segment earnings	$	264,616		784,405
Interest and other income		379		2,823
General and administrative expense		(18,046	)	(57,166	)
Administrative asset depreciation		(2,249	)	(6,018	)
Interest expense		(30,429	)	(86,265	)
Realized and unrealized gains (losses) on derivative instruments, net		449,340		(74,358	)
Gain on sale of assets		21,063		21,063
Other, net		(21,725	)	(32,779	)

Earnings before income taxes	$	662,949		551,705

			September 30, 2009													December 31, 2008

			Parent Company		Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated		Parent Company		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
	Cash and cash equivalents		$	655		86			4,412			—			5,153		1,226		74		905			—			2,205
	Accounts receivable			56,798		15,697			23,364			(322	)		95,537		106,941		22,003		28,584			(302	)		157,226
	Other current assets			190,159		837			10,315			—			201,311		304,424		471		8,723			—			313,618

		Total current assets		247,612		16,620			38,091			(322	)		302,001		412,591		22,548		38,212			(302	)		473,049
Property and equipment, at cost				7,564,021		1,276,811			1,698,985			—			10,539,817		7,327,978		1,259,337		1,465,891			—			10,053,206
	Less accumulated depreciation, depletion, and amortization			5,460,555		983,828			1,037,473			—			7,481,856		4,145,061		727,858		667,123			—			5,540,042

		Net property and equipment		2,103,466		292,983			661,512			—			3,057,961		3,182,917		531,479		798,768			—			4,513,164
Investment in subsidiaries				258,119		—			—			(258,119	)		—		577,405		—		—			(577,405	)		—
Note receivable from subsidiary				93,052		—			—			(93,052	)		—		93,052		—		—			(93,052	)		—
Deferred income taxes				342,390		—			—			(48,686	)		293,704		—		—		—			—			—
Goodwill				216,460		22,960			16,184			—			255,604		216,460		22,960		14,226			—			253,646
Due from (to) parent and subsidiaries				460,375		127,666			(588,041	)		—			—		391,074		141,656		(532,730	)		—			—
Other assets				47,679		6			2,480			—			50,165		40,607		5		2,327			—			42,939

			$	3,769,153		460,235			130,226			(400,179	)		3,959,435		4,914,106		718,648		320,803			(670,759	)		5,282,798

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable and accrued liabilities		$	162,107		7,492			24,508			(322	)		193,785		338,754		27,631		58,858			(302	)		424,941
	Other current liabilities			101,346		975			6,943			—			109,264		88,064		1,165		7,241			—			96,470

		Total current liabilities		263,453		8,467			31,451			(322	)		303,049		426,818		28,796		66,099			(302	)		521,411
Long-term debt				2,339,983		—			135,430			—			2,475,413		2,641,246		—		94,415			—			2,735,661
Note payable to parent				—		—			93,052			(93,052	)		—		—		—		93,052			(93,052	)		—
Other liabilities				137,953		2,851			34,581			—			175,385		128,017		3,397		35,813			—			167,227
Deferred income taxes				22,176		(1,932	)		28,442			(48,686	)		—		45,113		61,383		79,091			—			185,587

		Total liabilities		2,763,565		9,386			322,956			(142,060	)		2,953,847		3,241,194		93,576		368,470			(93,354	)		3,609,886
Shareholders' equity				1,005,588		450,849			(192,730	)		(258,119	)		1,005,588		1,672,912		625,072		(47,667	)		(577,405	)		1,672,912

			$	3,769,153		460,235			130,226			(400,179	)		3,959,435		4,914,106		718,648		320,803			(670,759	)		5,282,798

		Three Months Ended September 30,

		2009								2008
		Gas		Oil		NGLs		Total		Gas		Oil		NGLs		Total
		(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(MMcf)		(MBbls)		(MBbls)		(MMcfe)
Production volumes:
	United States		27,337		810		682		36,289		29,942		905		836		40,388
	Canada		6,246		149		54		7,464		5,808		205		73		7,476

Totals			33,583		959		736		43,753		35,750		1,110		909		47,864

Revenues (in thousands):
	United States	$	80,810		52,768		17,661		151,239		255,627		105,209		45,648		406,484
	Canada		15,912		8,531		1,502		25,945		40,464		21,659		5,630		67,753

Totals		$	96,722		61,299		19,163		177,184		296,091		126,868		51,278		474,237

Average sales price:
	United States	$	2.96		65.15		25.90		4.17		8.54		116.25		54.60		10.06
	Canada		2.55		57.26		27.81		3.48		6.97		105.65		77.12		9.06

Totals		$	2.88		63.92		26.04		4.05		8.28		114.30		56.41		9.91

	Fair Value of Derivative Contracts

	Commodity			Interest Rate			Total
	(In Thousands)
As of December 31, 2008	$	170,111			—			170,111
Premiums received		—			(3,657	)		(3,657	)
Net increase in fair value		102,029			13,734			115,763
Net contract gains recognized		(237,503	)		(6,925	)		(244,428	)

As of September 30, 2009	$	34,637			3,152			37,789

		2011

		(Dollar Amounts in Thousands)
Bank credit facilities:
	Variable rate	$	—		453,430		—		—		—		453,430
	Weighted average interest rate⁽¹⁾		—		1.5	%	—		—		—		1.5	%
Long-term debt:
	Fixed rate	$	285,000		—		112		750,000		1,000,000		2,035,112
	Weighted average coupon interest rate		8.00	%	—		7.00	%	8.35	%	7.25	%	7.76	%
	Weighted average effective interest rate⁽²⁾		7.71	%	—		7.00	%	8.11	%	7.25	%	7.63	%

Period		Average Price Per Share

July 2009	1,395	$	14.73	—	—
August 2009	858		16.40	—	—
September 2009	1,899		18.93	—	—

Third quarter	4,152	$	17.00	—	—


3.1		Restated Certificate of Incorporation of Forest Oil Corporation dated October 14, 1993, incorporated herein by reference to Exhibit 3(i) to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
3.2		Certificate of Amendment of the Restated Certificate of Incorporation, dated as of July 20, 1995, incorporated herein by reference to Exhibit 3(i)(a) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
3.3		Certificate of Amendment of the Certificate of Incorporation, dated as of July 26, 1995, incorporated herein by reference to Exhibit 3(i)(b) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
3.4		Certificate of Amendment of the Certificate of Incorporation dated as of January 5, 1996, incorporated herein by reference to Exhibit 3(i)(c) to Forest Oil Corporation Registration Statement on Form S-2 (File No. 33-64949).
3.5		Certificate of Amendment of the Certificate of Incorporation dated as of December 7, 2000, incorporated herein by reference to Exhibit 3(i)(d) to Form 10-K for Forest Oil Corporation for the year ended December 31, 2000 (File No. 001-13515).
3.6		Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, and No. 4, incorporated herein by reference to Exhibit 3.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).
10.1		Agreement for Purchase and Sale of Assets, dated as of August 5, 2009, by and among Forest Oil Corporation, Forest Oil Permian Corporation, Linn Operating, Inc. and Linn Energy Holdings, LLC, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated August 5, 2009 (File No. 001-13515).
31.1	*	Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
31.2	*	Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
32.1	⁺	Certification of Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
32.2	⁺	Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
101.INS	⁺⁺	XBRL Instance Document.


101.SCH	⁺⁺	XBRL Taxonomy Extension Schema Document.
101.CAL	⁺⁺	XBRL Taxonomy Calculation Linkbase Document.
101.LAB	⁺⁺	XBRL Label Linkbase Document.
101.PRE	⁺⁺	XBRL Presentation Linkbase Document.
101.DEF	⁺⁺	XBRL Taxonomy Extension Definition.

			Three Months Ended September 30,

			2009															2008
			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
	Oil and gas sales		$	121,119			29,664			26,401			—			177,184			321,716			31,275			121,246			—			474,237
	Interest and other			3,130			—			(117	)		(3,055	)		(42	)		5,042			18			138			(4,819	)		379
	Equity earnings in subsidiaries			35,072			—			—			(35,072	)		—			135,279			—			—			(135,279	)		—

		Total revenues		159,321			29,664			26,284			(38,127	)		177,142			462,037			31,293			121,384			(140,098	)		474,616
Costs, expenses, and other:
	Lease operating expenses			23,488			4,654			6,734			62			34,938			28,832			4,671			11,319			90			44,912
	Other direct operating costs			12,423			1,395			2,407			—			16,225			22,876			2,262			3,218			—			28,356
	General and administrative			14,838			586			1,892			—			17,316			15,977			45			2,024			—			18,046
	Depreciation, depletion, and amortization			42,165			8,933			14,856			(679	)		65,275			91,095			6,445			39,197			(6	)		136,731
	Interest expense			39,059			2,261			4,388			(3,055	)		42,653			26,868			—			8,380			(4,819	)		30,429
	Realized and unrealized (gains) losses on derivative instruments, net			(7,754	)		2,076			13			—			(5,665	)		(326,255	)		(78,316	)		(44,769	)		—			(449,340	)
	Gain on sale of assets			—			—			—			—			—			—			—			(21,063	)		—			(21,063	)
	Other, net			4,556			181			(6,928	)		131			(2,060	)		18,104			62			5,860			(430	)		23,596

		Total costs, expenses, and other		128,775			20,086			23,362			(3,541	)		168,682			(122,503	)		(64,831	)		4,166			(5,165	)		(188,333	)

Earnings (loss) before income taxes				30,546			9,578			2,922			(34,586	)		8,460			584,540			96,124			117,218			(134,933	)		662,949
		Income tax		(141,765	)		(19,733	)		(2,353	)		—			(163,851	)		155,533			34,915			43,494			—			233,942

Net earnings (loss)			$	172,311			29,311			5,275			(34,586	)		172,311			429,007			61,209			73,724			(134,933	)		429,007

			Nine Months Ended September 30,

			2009															2008
			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent Company		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
	Oil and gas sales		$	376,896			93,341			83,236			—			553,473			926,683		90,819		348,400			—			1,365,902
	Interest and other			9,948			91			(152	)		(9,285	)		602			15,222		389		346			(13,134	)		2,823
	Equity earnings in subsidiaries			(259,225	)		—			—			259,225			—			159,797		—		—			(159,797	)		—

		Total revenues		127,619			93,432			83,084			249,940			554,075			1,101,702		91,208		348,746			(172,931	)		1,368,725
Costs, expenses, and other:
	Lease operating expenses			77,178			15,392			21,504			131			114,205			77,642		10,724		32,390			134			120,890
	Other direct operating costs			38,338			4,869			7,070			—			50,277			61,762		6,431		13,928			—			82,121
	General and administrative			41,311			1,913			5,826			—			49,050			48,901		72		8,193			—			57,166
	Depreciation, depletion, and amortization			159,928			37,404			45,283			(4,651	)		237,964			250,996		17,917		109,980			(11	)		378,882
	Ceiling test write-down of oil and gas properties			1,155,777			218,567			201,499			—			1,575,843			—		—		—			—			—
	Interest expense			110,338			7,082			14,238			(9,285	)		122,373			75,237		—		24,162			(13,134	)		86,265
	Realized and unrealized (gains) losses on derivative instruments, net			(94,946	)		(17,003	)		(263	)		—			(112,212	)		89,466		35		(15,143	)		—			74,358
	Gain on sale of assets			—			—			—			—			—			—		—		(21,063	)		—			(21,063	)
	Other, net			10,498			322			(7,035	)		1,312			5,097			30,413		488		8,115			(615	)		38,401

		Total costs, expenses, and other		1,498,422			268,546			288,122			(12,493	)		2,042,597			634,417		35,667		160,562			(13,626	)		817,020

Earnings (loss) before income taxes				(1,370,803	)		(175,114	)		(205,038	)		262,433			(1,488,522	)		467,285		55,541		188,184			(159,305	)		551,705
		Income tax		(402,482	)		(63,339	)		(54,380	)		—			(520,201	)		111,028		20,139		64,281			—			195,448

Net earnings (loss)			$	(968,321	)		(111,775	)		(150,658	)		262,433			(968,321	)		356,257		35,402		123,903			(159,305	)		356,257


	FOREST OIL CORPORATION
	(Registrant)
November 6, 2009
	By:	/s/ DAVID H. KEYTE
		David H. Keyte
		Executive Vice President and Chief Financial Officer (on behalf of the Registrant and as Principal Financial Officer)
	By:	/s/ VICTOR A. WIND
		Victor A. Wind
		Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)