Edgar Filing: FOREST OIL CORP

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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 June 30, 2010
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 definitions 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 July 30, 2010 there were 113,331,476 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
June 30, 2010


Part I—FINANCIAL INFORMATION			1
	Item 1—Financial Statements		1
		Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	1
		Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009	2
		Condensed Consolidated Statement of Shareholders' Equity for the Six Months Ended June 30, 2010	3
		Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	4
		Notes to Condensed Consolidated Financial Statements	5
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations		27
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		40
	Item 4—Controls and Procedures		43
Part II—OTHER INFORMATION			45
	Item 1A.—Risk Factors		45
	Item 2—Unregistered Sales of Equity Securities and Use of Proceeds		45
	Item 6—Exhibits		46
Signatures			48

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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)

				June 30, 2010

ASSETS
Current assets:
	Cash and cash equivalents			$	200,786		467,221
	Accounts receivable				120,117		126,354
	Derivative instruments				73,111		35,643
	Deferred income taxes				—		7,108
	Inventory				40,332		52,211
	Other current assets				39,025		41,455

		Total current assets			473,371		729,992
Property and equipment, at cost:
	Oil and gas properties, full cost method of accounting:
		Proved, net of accumulated depletion of $7,607,960 and $7,511,661			1,596,818		1,316,712
		Unproved			824,674		828,645

			Net oil and gas properties		2,421,492		2,145,357
	Other property and equipment, net of accumulated depreciation and amortization of $52,595 and $54,810				96,128		113,850

			Net property and equipment		2,517,620		2,259,207
Deferred income taxes					346,134		393,061
Goodwill					255,696		255,908
Derivative instruments					15,410		556
Other assets					42,545		45,966

				$	3,650,776		3,684,690

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable and accrued liabilities			$	260,345		284,302
	Accrued interest				23,623		25,755
	Derivative instruments				17,752		41,358
	Deferred income taxes				17,665		—
	Current portion of long-term debt				—		156,678
	Asset retirement obligations				2,673		4,853
	Other current liabilities				20,174		22,074

		Total current liabilities			342,232		535,020
Long-term debt					1,867,534		1,865,836
Asset retirement obligations					83,548		88,450
Derivative instruments					3,157		826
Deferred income taxes					50,552		46,884
Other liabilities					70,115		68,520

	Total liabilities				2,417,138		2,605,536
Shareholders' equity:
	Preferred stock, none issued and outstanding				—		—
	Common stock, 113,349,373 and 112,337,315 shares issued and outstanding				11,335		11,234
	Capital surplus				2,667,817		2,652,689
	Accumulated deficit				(1,510,010	)	(1,652,426	)
	Accumulated other comprehensive income				64,496		67,657

	Total shareholders' equity				1,233,638		1,079,154

				$	3,650,776		3,684,690

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands, Except Per Share Amounts)

			Three Months Ended June 30,						Six Months Ended June 30,

			2010			2009			2010			2009
Revenues:
	Oil and gas sales		$	207,954			181,630			429,683			376,289
	Interest and other			141			435			277			644

Total revenues				208,095			182,065			429,960			376,933
Costs, expenses, and other:
	Lease operating expenses			28,422			38,036			57,524			79,267
	Production and property taxes			12,487			11,791			23,915			23,486
	Transportation and processing costs			6,020			5,322			10,879			10,566
	General and administrative			17,781			15,649			36,534			31,734
	Depreciation, depletion, and amortization			62,446			68,137			114,758			172,689
	Ceiling test write-down of oil and gas properties			—			—			—			1,575,843
	Interest expense			37,109			43,175			75,152			79,720
	Realized and unrealized (gains) losses on derivative instruments, net			(25,031	)		32,781			(118,242	)		(106,547	)
	Other, net			14,549			(3,964	)		6,555			7,157

		Total costs, expenses, and other		153,783			210,927			207,075			1,873,915
Earnings (loss) before income taxes				54,312			(28,862	)		222,885			(1,496,982	)
Income tax:
	Current			4,008			237			4,725			1,505
	Deferred			17,050			(66,240	)		75,744			(357,855	)

		Total income tax		21,058			(66,003	)		80,469			(356,350	)

Net earnings (loss)			$	33,254			37,141			142,416			(1,140,632	)

Basic earnings (loss) per common share			$	.29			.36			1.26			(11.58	)

Diluted earnings (loss) per common share			$	.29			.36			1.26			(11.58	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(Unaudited)

(In Thousands)

		Common Stock

		Common Stock						Capital Surplus			Accumulated Deficit					Total Shareholders' Equity
		Shares			Amount			Capital Surplus			Accumulated Deficit					Total Shareholders' Equity
Balances at December 31, 2009			112,337		$	11,234			2,652,689			(1,652,426	)	67,657			1,079,154
	Exercise of stock options		218			22			4,181			—		—			4,203
	Employee stock purchase plan		37			4			772			—		—			776
	Restricted stock issued, net of cancellations		877			88			(88	)		—		—			—
	Amortization of stock-based compensation		—			—			13,960			—		—			13,960
	Other, net		(120	)		(13	)		(3,697	)		—		—			(3,710	)
Comprehensive earnings:
	Net earnings		—			—			—			142,416		—			142,416
	Unfunded postretirement benefits, net of tax		—			—			—			—		685			685
	Foreign currency translation		—			—			—			—		(3,846	)		(3,846	)

	Total comprehensive earnings																139,255

Balances at June 30, 2010			113,349		$	11,335			2,667,817			(1,510,010	)	64,496			1,233,638

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)

			Six Months Ended June 30,

			2010			2009
Operating activities:
	Net earnings (loss)		$	142,416			(1,140,632	)
	Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
		Depreciation, depletion, and amortization		114,758			172,689
		Ceiling test write-down of oil and gas properties		—			1,575,843
		Deferred income tax		75,744			(357,855	)
		Unrealized (gains) losses on derivative instruments, net		(73,748	)		52,978
		Unrealized foreign currency exchange losses (gains), net		3,954			(5,886	)
		Unrealized losses on other investments, net		—			2,327
		Stock-based compensation expense		9,731			8,184
		Accretion of asset retirement obligations		3,748			4,181
		Other, net		(708	)		2,707
	Changes in operating assets and liabilities:
		Accounts receivable		5,900			61,161
		Other current assets		14,357			15,475
		Accounts payable and accrued liabilities		(46,577	)		(114,476	)
		Accrued interest and other current liabilities		(3,616	)		11,226

Net cash provided by operating activities				245,959			287,922
Investing activities:
	Capital expenditures for property and equipment:
		Exploration, development, and leasehold acquisition costs		(461,307	)		(441,680	)
		Other fixed assets		(2,791	)		(29,611	)
	Proceeds from sales of assets			107,198			29,703

Net cash used by investing activities				(356,900	)		(441,588	)
Financing activities:
	Proceeds from bank borrowings			92,480			587,190
	Repayments of bank borrowings			(92,480	)		(1,193,634	)
	Redemption of 7³/4% senior notes			(151,938	)		—
	Repurchases of 7% senior subordinated notes			(100	)		(970	)
	Issuance of 8¹/2% senior notes, net of issuance costs			—			559,767
	Proceeds from common stock offering, net of offering costs			—			256,253
	Proceeds from the exercise of options and from employee stock purchase plan			4,979			892
	Change in bank overdrafts			(2,387	)		(48,986	)
	Other, net			(5,438	)		(3,428	)

Net cash (used) provided by financing activities				(154,884	)		157,084
Effect of exchange rate changes on cash				(610	)		(127	)

Net (decrease) increase in cash and cash equivalents				(266,435	)		3,291
Cash and cash equivalents at beginning of period				467,221			2,205

Cash and cash equivalents at end of period			$	200,786			5,496

Cash paid during the period for:
	Interest		$	77,645			64,224
	Income taxes			68,048			5,489

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, consisting of normal recurring accruals, have been made which are necessary for a fair presentation of the financial position of Forest at June 30, 2010, the results of its operations for the three and six months ended June 30, 2010 and 2009, and its cash flows for the six months ended June 30, 2010 and 2009. 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.

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 2010 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, 2009, previously filed with the Securities and Exchange Commission ("SEC").

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

Earnings (Loss) per Share

Basic earnings (loss) per share is computed using the two-class method 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, unvested phantom stock units that may be settled in shares, and unvested performance units). 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 allocation formula that determines earnings per share for each class of common stock and participating

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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)

security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Holders of restricted stock issued under Forest's stock incentive plans have the right to receive non-forfeitable cash dividends, participating on an equal basis with common stock. Holders of 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. Performance units issued under Forest's stock incentive plans do not participate in dividends in their current form. Holders of performance units participate in dividends paid during the performance units' vesting period only after the performance units vest with common shares being earned by the holders of the performance units. Performance units may vest with no common shares being earned, depending on Forest's shareholder return over the performance units' vesting period in relation to the shareholder returns of specified peers. See Note 3 for more information on the performance units. In summary, restricted stock issued to employees and directors and phantom stock units issued to directors are participating securities and earnings are 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.

Unvested restricted stock grants were not included in the calculation of diluted earnings per share for the three and six months ended June 30, 2010 as their inclusion would have an antidilutive effect. Unvested restricted stock grants and unvested participating phantom stock units that may be settled in shares were not included in the calculation of diluted earnings per share for the three months ended June 30, 2009 as their inclusion would have an antidilutive effect. 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 six months ended June 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 June 30,						Six Months Ended June 30,

	2010			2009			2010			2009
	(In Thousands, Except Per Share Amounts)
Net earnings (loss)	$	33,254			37,141			142,416			(1,140,632	)
Net earnings attributable to participating securities		(656	)		(638	)		(2,685	)		—

Net earnings (loss) attributable to common stock for basic earnings per share		32,598			36,503			139,731			(1,140,632	)
Adjustment for liability-classified stock-based compensation awards		151			(162	)		177			—

Net earnings (loss) for diluted earnings per share	$	32,749			36,341			139,908			(1,140,632	)

Weighted average common shares outstanding during the period for basic earnings per share		110,660			101,314			110,538			98,458
Dilutive effects of potential common shares		796			279			671			—

Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings per share		111,456			101,593			111,209			98,458

Basic earnings (loss) per common share	$	.29			.36			1.26			(11.58	)

Diluted earnings (loss) per common share	$	.29			.36			1.26			(11.58	)

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 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 six months ended June 30, 2010 and 2009 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.

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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 components of comprehensive earnings (loss) are as follows:

		Three Months Ended June 30,					Six Months Ended June 30,

		2010			2009		2010			2009
		(In Thousands)
Net earnings (loss)		$	33,254			37,141		142,416			(1,140,632	)
Other comprehensive income (loss):
	Foreign currency translation (losses) gains		(12,988	)		16,858		(3,846	)		4,032
	Unfunded postretirement benefits, net of tax		290			632		685			668

Total comprehensive earnings (loss)		$	20,556			54,631		139,255			(1,135,932	)

(3) STOCK-BASED COMPENSATION

The table below sets forth total stock-based compensation recorded during the three and six months ended June 30, 2010 and 2009, and the remaining unamortized amounts and weighted average amortization period as of June 30, 2010.

		Stock Options

		(In Thousands)
Three months ended June 30, 2010:
	Total stock-based compensation costs	$	8		6,633		1,261		7,902
	Less: stock-based compensation costs capitalized		(3	)	(2,036	)	(543	)	(2,582	)

	Stock-based compensation costs expensed	$	5		4,597		718		5,320

Six months ended June 30, 2010:
	Total stock-based compensation costs	$	230		13,454		2,529		16,213
	Less: stock-based compensation costs capitalized		(96	)	(4,727	)	(1,132	)	(5,955	)

	Stock-based compensation costs expensed	$	134		8,727		1,397		10,258

Unamortized stock-based compensation costs		$	631		45,983		8,426	⁽³⁾	55,040
Weighted average amortization period remaining			1.0 year		2.2 years		2.2 years		2.2 years
Three months ended June 30, 2009:
	Total stock-based compensation costs	$	60		6,664		377		7,101
	Less: stock-based compensation costs capitalized		(27	)	(2,741	)	(198	)	(2,966	)

	Stock-based compensation costs expensed	$	33		3,923		179		4,135

Six months ended June 30, 2009:
	Total stock-based compensation costs	$	337		12,648		301		13,286
	Less: stock-based compensation costs capitalized		(152	)	(5,087	)	(153	)	(5,392	)

	Stock-based compensation costs expensed	$	185		7,561		148		7,894

⁽¹⁾: Includes performance units.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) STOCK-BASED COMPENSATION (Continued)

⁽²⁾: The Company also maintains an employee stock purchase plan (which is not included in the table) under which $.1 million and $.3 million of compensation cost was recognized for the three and six months ended June 30, 2010, respectively, and $.2 million and $.3 million of compensation cost was recognized for the three and six months ended June 30, 2009, respectively.
⁽³⁾: Based on the closing price of the Company's common stock on June 30, 2010.

Stock Options

The following table summarizes stock option activity in the Company's stock-based compensation plans for the six months ended June 30, 2010.

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

Outstanding at January 1, 2010	1,818,419		$	21.26	$	7,387	1,722,216
Granted	—
Exercised	(217,685	)		19.31		1,624
Cancelled	(24,414	)		34.33

Outstanding at June 30, 2010	1,576,320		$	21.33	$	12,909	1,530,907

⁽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 six months ended June 30, 2010.

	Restricted Stock⁽¹⁾							Phantom Stock Units⁽²⁾

	Number of Shares			Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)		Number of Units			Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)⁽³⁾
Unvested at January 1, 2010		2,028,683		$	39.44				475,063		$	27.91
Awarded		1,212,843			25.97				122,185			24.46
Vested		(506,845	)		40.03	$	15,386		(59,440	)		42.00	$	1,741
Forfeited		(71,010	)		37.53				(28,991	)		37.01

Unvested at June 30, 2010		2,663,671		$	33.25				508,817		$	24.92

⁽¹⁾: Includes performance units that were awarded to Forest's officers on May 21, 2010. There were 264,500 performance units awarded, with a grant date fair value of $31.63 each. Under the terms of the award agreements, each performance unit represents a contractual right to receive one share of Forest's common stock; provided that the actual number of shares that may be deliverable under an award will range from 0% to 200% of the number of performance units awarded, depending on Forest's relative total shareholder return in comparison to an identified peer group during the thirty-six month performance period ending on March 31, 2013.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) STOCK-BASED COMPENSATION (Continued)

⁽²⁾: Of the unvested units of phantom stock at June 30, 2010, 264,085 units can be settled in cash, shares of common stock, or a combination of both, while the remaining 244,732 units can only be settled in cash. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements.
⁽³⁾: Of the 59,440 phantom stock units that vested during the six months ended June 30, 2010, 59,000 units were settled in shares of common stock and 440 units were settled in cash.

(4) DEBT

The components of debt are as follows:

	June 30, 2010									December 31, 2009

	Principal		Unamortized Premium (Discount)			Other⁽¹⁾		Total		Principal			Unamortized Premium (Discount)			Other⁽¹⁾			Total
	(In Thousands)
Credit Facilities	$	—		—			—		—		—			—			—			—
8% Senior Notes due 2011⁽²⁾		285,000		1,938			1,222		288,160		285,000			2,583			1,638			289,221
7% Senior Subordinated Notes due 2013⁽³⁾		12		—			—		12		112			(2	)		—			110
8¹/2% Senior Notes due 2014		600,000		(21,144	)		—		578,856		600,000			(24,029	)		—			575,971
7³/4% Senior Notes due 2014⁽⁴⁾		—		—			—		—		150,000			(1,035	)		7,713			156,678
7¹/4% Senior Notes due 2019		1,000,000		506			—		1,000,506		1,000,000			534			—			1,000,534

Total long-term debt		1,885,012		(18,700	)		1,222		1,867,534		2,035,112			(21,949	)		9,351			2,022,514
Less: current portion of long-term debt⁽⁴⁾		—		—			—		—		(150,000	)		1,035			(7,713	)		(156,678	)

Long-term portion of long-term debt	$	1,885,012		(18,700	)		1,222		1,867,534		1,885,112			(20,914	)		1,638			1,865,836

⁽¹⁾: Represents the unamortized portion of gains realized upon termination of interest rate swaps in 2002 and 2003 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.
⁽²⁾: Due December 2011.
⁽³⁾: In May 2010, the Company repurchased $.1 million in principal amount of the 7% senior subordinated notes due 2013 at par.
⁽⁴⁾: In December 2009, the Company irrevocably called the 7³/4% senior notes due 2014 and redeemed these notes in January 2010 at 101.292% of par and a net gain of $4.6 million was recognized upon redemption. The net gain was recognized due to the write-off of unamortized deferred gains on the termination of interest rate swaps.

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(Unaudited)

(4) DEBT (Continued)

Bank Credit Facilities

As of June 30, 2010, the Company had syndicated bank revolving credit agreements with total lender commitments of $1.8 billion. The credit agreements consist of a $1.65 billion U.S. credit facility through a syndicate of banks led by JPMorgan Chase Bank, N.A. (the "U.S. Credit Facility") and a $150 million Canadian credit facility through a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch (the "Canadian Credit Facility," and together with the U.S. Credit Facility, the "Credit Facilities"). The Credit Facilities will mature in June 2012. At June 30, 2010, there were no outstanding borrowings under the Credit Facilities.

Forest's availability under the Credit Facilities is governed by a borrowing base (the "Global Borrowing Base"). As of June 30, 2010, the borrowing base under the Credit Facilities was $1.3 billion, which Forest has allocated $1.155 billion to the U.S. Credit Facility and $145 million to the Canadian Credit Facility. The determination of the Global Borrowing Base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of Forest's oil and gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders' customary practices for oil and gas loans. The available borrowing amount under the Credit Facilities could increase or decrease based on such redetermination. In April 2010, the lenders reaffirmed the borrowing base at $1.3 billion and the next redetermination is expected to occur in the third or fourth 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. The Global Borrowing Base is also subject to automatic adjustments if certain events occur.

(5) PROPERTY AND EQUIPMENT

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 June 30, 2010 and 2009, Forest capitalized $10.5 million and $11.6 million of general and administrative costs (including stock-based compensation), respectively. During the six months ended June 30, 2010 and 2009, Forest capitalized $22.6 million and $22.1 million of general and 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 June 30, 2010 and 2009, the Company capitalized $3.1 million and $3.4 million, respectively, of interest costs attributed to unproved properties. During the six months ended June 30, 2010 and 2009, the Company capitalized $5.9 million and $6.8 million, respectively, of interest costs attributed to unproved properties.

Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to

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(5) PROPERTY AND EQUIPMENT (Continued)

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, geographic and geologic data obtained relating to the properties, and estimated discounted future net cash flows from the properties. Estimated discounted future net cash flows are based on discounted future net revenues associated with probable and possible reserves, risk adjusted as appropriate. 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.

The Company performs a ceiling test each quarter on a country-by-country basis. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. 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 (as discussed below), 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. The June 30, 2010 ceiling test, which did not result in a write-down, was based on average prices during the twelve-month period prior to June 30, 2010 pursuant to the SEC's "Modernization of Oil and Gas Reporting" rule, which was effective beginning with December 31, 2009 reporting. The March 31, 2009 ceiling test, which was based on the March 31, 2009 spot prices, resulted in non-cash write-downs of oil and gas property costs of $1.4 billion in the United States cost center and $199.0 million in the Canada cost center.

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.

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. The Company uses its quarter-end reserves estimates to calculate depletion for the current quarter.

(6) 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. Subsequent to initial measurement, the asset retirement obligation 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

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(Unaudited)

(6) ASSET RETIREMENT OBLIGATIONS (Continued)

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 six months ended June 30, 2010 and 2009.

	Six Months Ended June 30,

	2010			2009
	(In Thousands)
Asset retirement obligations at beginning of period	$	93,303			96,991
Accretion expense		3,748			4,181
Liabilities incurred		1,461			2,334
Liabilities settled		(614	)		(2,153	)
Disposition of properties		(7,143	)		(2,138	)
Revisions of estimated liabilities		(4,282	)		(3,922	)
Impact of foreign currency exchange rate		(252	)		513

Asset retirement obligations at end of period		86,221			95,806
Less: current asset retirement obligations		(2,673	)		(4,368	)

Long-term asset retirement obligations	$	83,548			91,438

(7) FAIR VALUE MEASUREMENTS

The Company's assets and liabilities measured at fair value on a recurring basis at June 30, 2010 are set forth in the table below.

Description			Using Significant Other Observable Inputs (Level 2)⁽¹⁾

			(In Thousands)
Assets:
	Derivative instruments⁽²⁾
		Commodity	$	70,133
		Interest rate		18,388

Total assets			$	88,521

Liabilities:
	Derivative instruments⁽²⁾
		Commodity	$	20,904
		Interest rate		5

Total liabilities			$	20,909

⁽¹⁾: The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities;

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(7) FAIR VALUE MEASUREMENTS (Continued)

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 hierarchy.

⁽²⁾: The Company's derivative assets and liabilities include commodity and interest rate derivatives (see Note 8 for more information on these instruments). The Company utilizes present value techniques and option-pricing models for valuing its derivatives. 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.

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 six months ended June 30, 2009. The Company did not have assets or liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) at any time during 2010.

			Six Months Ended June 30, 2009

			Equity Securities			Debt Securities⁽¹⁾
			(In Thousands)
Balance at beginning of period			$	—			1,670
	Total losses (realized/unrealized):
		Included in earnings		(657	)		(1,670	)
		Included in other comprehensive income		—			—
	Purchases, issuances, sales, and settlements:
		Purchases		—			—
		Issuances		—			—
		Sales		—			—
		Settlements		—			—
	Transfers in and/or out of Level 3⁽²⁾⁽³⁾			657			—

Balance at end of period			$	—			—

The amount of total 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			$	(657	)		(1,670	)

⁽¹⁾: The Company's 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") that was received as a portion of the total consideration for the sale of the Company's Alaska assets in 2007. In March 2009, PERL filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Company used its own assumptions as to what market participants would assume regarding future cash flows and risk-adjusted discount rates in valuing the PERL Note, which is currently valued at zero and has been since March 31, 2009.
⁽²⁾: The Company's investment in PERL common stock, which the Company also received as a portion of the total consideration for the sale of the Company's Alaska assets in 2007, was transferred from Level 1 to Level 3 in the first quarter of 2009 when PERL's common stock was suspended from trading for failure to meet the continued

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(7) FAIR VALUE MEASUREMENTS (Continued)

stock exchange listing requirements. The Company used its own assumptions as to what market participants would assume regarding future cash flows and risk-adjusted discount rates in valuing the PERL common stock, which is currently valued at zero and has been since March 31, 2009.

⁽³⁾: The Company's policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

The table below sets forth 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 six months ended June 30, 2009, which are reported in the Condensed Consolidated Statements of Operations under "Other, net." The Company did not record any gains or losses (realized and unrealized) related to assets or liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during 2010 or the three months ended June 30, 2009.

	Six Months Ended June 30, 2009

	Equity Securities		Debt Securities
	(In Thousands)
Total losses included in earnings for the period	$	657		1,670

Change in unrealized losses relating to assets still held at end of period	$	657		1,670

The fair values and carrying amounts of the Company's financial instruments are summarized below for the periods presented.

		June 30, 2010				December 31, 2009

		Carrying Amount		Fair Value⁽¹⁾		Carrying Amount		Fair Value⁽¹⁾
		(In Thousands)
Assets:
	Cash and cash equivalents	$	200,786		200,786		467,221		467,221
	Derivative instruments		88,521		88,521		36,199		36,199
Liabilities:
	Derivative instruments		20,909		20,909		42,184		42,184
	8% senior notes due 2011		288,160		302,100		289,221		296,400
	7% senior subordinated notes due 2013		12		12		110		112
	8¹/2% senior notes due 2014		578,856		636,000		575,971		630,000
	7³/4% senior notes due 2014		—		—		156,678		151,938
	7¹/4% senior notes due 2019		1,000,506		1,005,000		1,000,534		992,500

⁽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 fair values of the senior notes and senior subordinated notes were estimated based on quoted market prices. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 8 to the Condensed Consolidated Financial Statements for more information on the derivative instruments.

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(Unaudited)

(8) 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 the Company's 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.

The table below sets forth Forest's outstanding commodity swaps and costless collars as of June 30, 2010.

Commodity Swaps and Collars

		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:
	July 2010 - December 2010		210	$	6.20		3,000	$	76.06
	Calendar 2011		55		6.02		—		—
Collars:
	July 2010 - December 2010		—		—		2,000		60.00/98.50	⁽¹⁾
	Calendar 2011		—		—		3,000		75.00/91.87	⁽¹⁾⁽²⁾

⁽¹⁾: Represents weighted average hedged floor and ceiling price per Bbl.
⁽²⁾: In May 2010, Forest lowered the hedged ceiling price on one of its existing Calendar 2011 oil collars covering 1,000 barrels per day from $105.00 per Bbl to $90.00 per Bbl in exchange for a new natural gas swap with a premium hedged price of $6.05 per MMBtu covering 10 Bbtu per day for Calendar 2011 with the same counterparty.

In connection with several new gas swaps entered into during the second quarter of 2010, Forest also entered into commodity swaptions that enable the counterparties to exercise options to either enter into commodity swaps or increase the Bbtu per day on certain existing swaps, as the case may be, with Forest in exchange for Forest receiving premium hedged prices on the commodity swaps. During the three months ended June 30, 2010, Forest entered into gas swaps covering 45 Bbtu per day for Calendar 2011 at a weighted average hedged price of $6.02 per MMBtu. In connection with these swaps, the counterparties were granted the following commodity swaptions, which were outstanding as of June 30, 2010.

Commodity Swaptions

		Natural Gas (NYMEX HH)				Oil (NYMEX WTI)
Option Expiration	Underlying Swap Term	Underlying Swap Bbtu Per Day		Underlying Swap Weighted Average Hedged Price per MMBtu		Underlying Swap Barrels Per Day		Underlying Swap Hedged Price per Bbl
December 2010	Calendar 2011		30	$	6.00		—	$	—
December 2011	Calendar 2012		—		—		1,000		90.00

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(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

Subsequent to June 30, 2010, through August 3, 2010, Forest entered into three additional gas swaps covering 35 Bbtu per day for Calendar 2011 for a weighted average hedged price of $5.61 per MMBtu. In connection with these swaps, Forest granted commodity swaptions, which expire in December 2010, that enable the counterparties to exercise options to double the Bbtu per day on the gas swaps covering 20 Bbtu per day at a weighted average hedged price of $5.51 per MMBtu and granted a $90.00 per Bbl call option on 1,000 barrels of oil per day for Calendar 2011.

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 a portion of its natural gas production is sold. The table below sets forth Forest's outstanding basis swaps as of June 30, 2010.

Forest periodically enters into interest rate derivative agreements in an attempt to manage the mix of fixed and floating interest rates within its debt portfolio. 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. The table below sets forth Forest's outstanding fixed-to-floating interest rate swaps as of June 30, 2010.

In addition to interest rate swaps, Forest periodically enters into interest rate swaptions that enable the counterparties to exercise options to enter into interest rate swaps with Forest in exchange for premiums paid to Forest. The premiums received on these swaptions are amortized as realized gains on derivatives over the terms of the related swaptions. Forest has entered into these interest rate swaptions because its targeted floating interest rates were not attainable at the 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 June 30, 2010.

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 7 to the Condensed Consolidated Financial Statements for more information on the fair values of Forest's derivative instruments.

The table below summarizes the amount of derivative instrument gains and losses reported in the Condensed Consolidated Statements of Operations as "Realized and unrealized (gains) losses on

derivative instruments, net," for the periods indicated. These derivative instruments are not designated as hedging instruments for accounting purposes.

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. 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. None of these counterparties require collateral beyond that already pledged under the Credit Facilities. The remaining counterparty, a purchaser of Forest's natural gas production, generally is a net debtor to Forest and as a result of these purchases does not require collateral under the ISDA Master Agreement and Schedule it has executed with Forest. Forest is currently evaluating the impact, if any, that the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act will have on the existing derivative transactions under the Company's currently outstanding ISDA Master Agreements and Schedules, as well as Forest's ability to enter into such transactions and agreements in the future.

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 if there were 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 $71.0 million at June 30, 2010. 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 June 30, 2010, Forest owed a net derivative liability to four counterparties, the fair value of which was $3.4 million.

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

The table below sets forth the components of "Other, net" in the Condensed Consolidated Statements of Operations for the periods indicated.

At June 30, 2010, 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 to consolidated earnings before income taxes is as follows:

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

The Company's 8% senior notes due 2011, 8¹/2% 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 June 30, 2010 and December 31, 2009 and for the six months ended June 30, 2010 and 2009 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Elimination entries presented are necessary to combine the entities.

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

Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of natural gas and liquids primarily 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: the United States, Canada, and International. Our core operational areas, where the majority of our exploration and development activities are planned in 2010, are the Texas Panhandle area, the East Texas / North Louisiana area, and the Canadian Deep Basin area in Alberta and British Columbia. Our total estimated proved reserves as of December 31, 2009 were approximately 2,121 Bcfe. At December 31, 2009, approximately 83% of our estimated proved oil and natural gas reserves were in the United States, approximately 15% were in Canada, and approximately 2% were in Italy. Approximately 80% of our estimated proved reserves were natural gas as of December 31, 2009. See Note 11 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 or incorporated by reference in Forest's 2009 Annual Report on Form 10-K under the headings "Risk Factors," and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions."

Forest's second quarter and year-to-date 2010 highlights and other significant items were as follows:

Forest reported net earnings of $33 million in the second quarter of 2010, or $.29 per diluted share, compared to net earnings of $37 million, or $.36 per diluted share, in the second quarter 2009. The decrease in net earnings in the second quarter 2010 compared to the second quarter 2009 was primarily due to a $53 million reduction of a valuation allowance on a portion of our deferred tax assets during the second quarter 2009. Earnings before income taxes increased $83 million between the two quarterly periods due to increased commodity prices and an increase in realized and unrealized gains on derivatives. Forest reported net earnings of $142 million in the first six months of 2010, or $1.26 per diluted share, compared to a net loss of $1.1 billion, or $11.58 per diluted share, in the first six months of 2009. The increase in net earnings in the first six months of 2010 is primarily due to a $1.6 billion non-cash ceiling test write-down recorded in the first quarter 2009, which was caused by the significant decline in spot natural gas prices at March 31, 2009. Higher realized oil and gas prices in the first six months of 2010 as compared to the first six months of 2009 also contributed to the increase in net earnings; however, the increase in realized prices was somewhat offset by a decrease in realized gains on derivative instruments and a decrease in production between the two periods due to non-core oil and gas property divestitures that occurred primarily in late 2009.

Forest's earnings before interest expense; income taxes; depletion, depreciation, and amortization expense; and certain other items ("Adjusted EBITDA"), were $181 million and $200 million for the quarters ended June 30, 2010 and 2009, respectively, and were $352 million and $393 million for the first six months of June 30, 2010 and 2009, respectively. The fluctuation in Adjusted EBITDA between the periods presented was primarily driven by changes in oil and gas revenues and realized gains and losses on oil and gas derivative instruments, each as discussed below. Adjusted EBITDA is not considered a performance measure under U.S. Generally Accepted Accounting Principles ("GAAP") and reference should be made to "Reconciliation of Non-GAAP Measures" at the end of this Item 2 for further explanation of this performance measure, as well as a reconciliation to the most directly comparable GAAP measure. Discussion of the components of the changes in our quarterly and year-to-date results follows.

Oil and gas production volumes, revenues, and average sales prices by product and location for the three and six months ended June 30, 2010 and 2009 are set forth in the tables below.

Net oil and gas production in the second quarter 2010 decreased 11% to 464 MMcfe per day from 521 MMcfe per day in the second quarter 2009. Net oil and gas production in the first six months of 2010 decreased 18% to 440 MMcfe per day from 535 MMcfe per day in the first six months of 2009. The decrease in oil and gas production for the comparable three and six month periods was due to non-core oil and gas property divestitures that occurred primarily in late 2009. Oil and gas revenues were $208 million in the second quarter 2010, a 14% increase as compared to $182 million in the second quarter 2009. Oil and gas revenues were $430 million in the first six months of 2010, a 14% increase as compared to $376 million in the first six months of 2009. The increase in oil and gas revenues between the comparable three and six month periods was primarily due to a 29% and 39%

increase in average realized sales prices, respectively, partially offset by the decrease in production discussed above.

The table below sets forth the detail of oil and gas production expense for the three and six months ended June 30, 2010 and 2009.

Lease operating expenses in the second quarter 2010 were $28 million, or $.67 per Mcfe, compared to $38 million, or $.80 per Mcfe, in the second quarter 2009. Lease operating expenses in the first six months of 2010 were $57 million, or $.72 per Mcfe, compared to $79 million, or $.82 per Mcfe, in the first six months of 2009. The $10 million and $22 million decrease in lease operating expense between the comparable three and six month periods, respectively, was primarily due to the non-core oil and gas property divestitures that occurred during late 2009. Lease operating expenses on a per-Mcfe basis also decreased between the periods presented due to cost reduction initiatives and the sale of non-core oil and gas properties in late 2009 that had higher average per-unit operating costs as compared to the properties we retained.

Production and property taxes, which primarily consist of severance taxes paid on the value of the oil and gas produced, generally fluctuate proportionately to our oil and gas revenues. As a percentage of oil and natural gas revenue, production and property taxes were 6.0% and 6.5% for the three months ended June 30, 2010 and 2009, respectively, and 5.6% and 6.2% for the six months ended June 30, 2010 and 2009, respectively. Normal fluctuations occur in the percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, and changes in the assessed values of property and equipment for purposes of ad valorem taxes.

Transportation and processing costs in the second quarter 2010 were $6 million, or $.14 per Mcfe, compared to $5 million, or $.11 per Mcfe, in the second quarter 2009. Transportation and processing costs in the first six months of 2010 were $11 million, or $.14 per Mcfe, compared to $11 million, or $.11 per Mcfe, in the first six months of 2009. Transportation and processing costs increased slightly between comparable periods due to higher transportation costs in Canada and processing costs in other areas.

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

General and administrative expense in the second quarter 2010 was $18 million compared to $16 million in the second quarter 2009. General and administrative expense in the first six months of 2010 was $37 million compared to $32 million in the first six months of 2009. The increases in general and administrative expense in the comparable three and six month periods were primarily due to higher incentive stock-based compensation costs. The percentage of general and administrative costs capitalized under the full cost method of accounting was relatively consistent between each of the periods presented, ranging from 37% to 43%.

Depreciation, depletion, and amortization expense ("DD&A") in the second quarter 2010 was $62 million, or $1.48 per Mcfe, compared to $68 million, or $1.44 per Mcfe, in the second quarter 2009. For the six months ended June 30, 2010, DD&A was $115 million, or $1.44 per Mcfe, compared to $173 million, or $1.78 per Mcfe, for the first six months of 2009. The decrease of $.34 per Mcfe between the six-month periods was primarily due to a $1.6 billion non-cash ceiling test write-down recorded in the first quarter 2009.

In the first quarter 2009, Forest recorded a $1.6 billion ceiling test write-down related to its 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 write-down was primarily a result of a significant decline in natural gas prices in the first quarter of 2009. The March 31, 2009 spot price for natural gas was $3.63 per MMBtu compared to $5.71 at December 31, 2008. Our June 30, 2010 ceiling test calculation, which was calculated using $4.10 per MMBtu and $75.92 per barrel, which are the average natural gas and oil prices, respectively, for the twelve months prior to June 30, 2010, did not result in a ceiling test write-down.

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

Interest expense in the second quarter 2010 totaled $37 million compared to $43 million in the second quarter 2009. Interest expense was $75 million and $80 million for the six months ended June 30, 2010 and 2009, respectively. Although our outstanding debt decreased to $1.9 billion as of June 30, 2010 from $2.7 billion as of June 30, 2009, interest expense did not decrease proportionately given the fact that the majority of the debt reduction was attributable to a reduction of borrowings under our bank credit facilities (which had a variable interest rate that averaged less than 2% in the first six months of 2009). In order to effectively reduce the concentration of fixed-rate debt anticipated after the completion of our 2009 oil and gas property divestiture program and the related reduction in outstanding debt, Forest entered into fixed-to-floating interest rate swaps under which it has swapped, as of June 30, 2010, $500 million in notional amount at an 8.5% fixed rate for an equal notional amount at a weighted-average rate equal to the 1-month LIBOR plus approximately 5.9%. Forest recognized realized gains under its interest rate swaps of $3 million and $6 million during the three and six months ended June 30, 2010, respectively, and $.6 million and $.9 million during the three and six months ended June 30, 2009, respectively. These gains are recorded as realized gains on derivatives rather than as a reduction to interest expense since Forest has not elected to use hedge accounting. See Note 8 to the Condensed Consolidated Financial Statements for more information on our interest rate derivatives.

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 7 and Note 8 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.

The table below sets forth the components of "Other, net" in our Condensed Consolidated Statements of Operations for the periods indicated.

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

Unrealized losses on other investments 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. See Note 7 to the Condensed Consolidated Financial Statements for more information on these investments.

Accretion of asset retirement obligations is the expense recognized to increase the carrying amount of the liability associated with our asset retirement obligations as a result of the passage of time. See Note 6 to the Condensed Consolidated Financial Statements for more information on our asset retirement obligations.

The loss on debt extinguishment for the three months ended June 30, 2010 relates to the write-off of the unamortized discount associated with the $.1 million of 7% senior subordinated notes due 2013 that were repurchased during the quarter at par. The net gain on debt extinguishment for the six months ended June 30, 2010 includes the aforementioned loss as well as a net gain related to the January 2010 redemption of all $150 million of our 7³/4% senior notes due 2014 at 101.292% of par. The net gain was recognized due to the write-off of unamortized deferred gains on the termination of interest rate swaps. See Note 4 to the Condensed Consolidated Financial Statements for more information on our debt.

Our combined U.S. and Canadian effective tax rate should generally approximate 36% of pre-tax income but will fluctuate based on the percentage of pre-tax income generated in the U.S. versus Canada. Our effective income tax rate was 39% and 36% for the three and six months ended June 30, 2010, respectively, and 229% and 24% for the three and six months ended June 30, 2009, respectively. The significant changes in our effective tax rates in the 2009 periods as compared to the 2010 periods are primarily due to the valuation allowances placed on a portion of our deferred tax assets in the United States during 2009. See Note 9 to the Condensed Consolidated Financial Statements for a reconciliation of our income taxes at the statutory U.S. federal rate to income taxes at our effective rate for each period presented.

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. For the six months ended June 30, 2010, natural gas accounted for approximately 76% of our total oil and gas production 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 August 3, 2010, we had hedged, via commodity swaps and collar instruments, approximately 86 Bcfe of our total 2010 production and 39 Bcfe, excluding outstanding swaptions and call options, of our total 2011 production. We expect that 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 2010 and 2011. 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 combined U.S. and Canadian credit facilities, which had an aggregate borrowing base of $1.3 billion as of June 30, 2010. 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. See—"Bank Credit Facilities" below for further details. We had no amounts drawn on our credit facilities as of June 30, 2010 and July 31, 2010.

The public and private capital markets have historically 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 for net proceeds of $560 million and in May 2009, we issued approximately 14 million shares of common stock for net proceeds of $256 million. 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 2009, we sold certain non-strategic assets for approximately $1.1 billion, a portion of which proceeds were used to pay off the outstanding balances under our credit facilities in 2009 and redeem our 7³/4% senior notes due 2014 in January 2010. During the first six months of 2010 we have sold additional non-strategic assets for total proceeds of $107 million.

We believe that our current cash and cash equivalents, cash flows provided by operating activities, and $1.3 billion of funds available under our credit facilities will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures, and our contractual obligations. However, if our revenue and cash flow decrease in the future as a result of a deterioration in domestic and global economic conditions or a significant decline in commodity prices, we may elect to reduce our planned capital expenditures. 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.

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"), which was $1.3 billion as of June 30, 2010. We currently have allocated $1.155 billion to the borrowing base under the U.S. Facility and $145 million to the borrowing base under the Canadian Facility. The determination of the Global Borrowing Base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil

and gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders' customary practices for oil and gas loans. The available borrowing amount under the Credit Facilities could increase or decrease based on such redetermination. In April 2010, the lenders reaffirmed the borrowing base at $1.3 billion and the next redetermination is expected to occur in the third or fourth 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. The Global Borrowing Base is also subject to automatic adjustments if certain events occur.

As of June 30, 2010 and July 31, 2010, there were no outstanding borrowings under our Credit Facilities. We had used the Credit Facilities for approximately $2 million in letters of credit at June 30, 2010.

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 August 3, 2010, our primary derivative counterparties are lenders and their affiliates, with six such lenders accounting for approximately 78 Bcfe, or 91% of our 2010 hedged production and approximately 27 Bcfe, or 68% of our 2011 hedged production, excluding outstanding swaptions and call options. 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 Part 3—"Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk," below for additional details concerning our derivative arrangements.

Net cash provided by operating activities, net cash used by investing activities, and net cash (used) provided by financing activities for the six months ended June 30, 2010 and 2009 were as follows:

Net cash provided by operating activities is primarily affected by production volumes, commodity prices, the effects of settlements of our derivative contracts, and changes in working capital. The decrease in net cash provided by operating activities in the six months ended June 30, 2010 compared to the same period of 2009 was primarily due to lower realized gains on our derivative contracts offset somewhat by higher average sales prices and a decreased investment in net operating assets (i.e., working capital) during the six months ended June 30, 2010. Adjusted discretionary cash flow, which is a non-GAAP liquidity measure that management uses to evaluate cash flow from operations before changes in working capital, was $276 million and $315 million for the six months ended June 30, 2010 and 2009, respectively. The decrease in adjusted discretionary cash flow between the six-month periods was primarily driven by a decrease in realized gains on oil and gas derivative instruments. Reference should be made to "Reconciliation of Non-GAAP Measures" at the end of this Item 2 for further explanation of this non-GAAP liquidity measure, as well as a reconciliation to the most directly comparable GAAP measure.

Net cash used by investing activities is primarily comprised of expenditures for the exploration and development of oil and gas properties and leasehold acquisition costs net of proceeds from the dispositions of oil and gas properties. The decrease in net cash used by investing activities in the six

months ended June 30, 2010 compared to the same period of 2009 was primarily due to increased proceeds from sales of assets during the six months ended June 30, 2010 as compared to the same period of 2009. The major components of cash used by investing activities for the six months ended June 30, 2010 and 2009 were as follows:

Net cash used by financing activities in the six months ended June 30, 2010 included the redemption of the 7³/4% senior notes for $152 million. Net cash provided by financing activities in the six months ended June 30, 2009 included the issuance of the 8¹/2% senior notes for net proceeds of $560 million and the issuance of common stock for proceeds of $256 million partially offset by net repayments of bank borrowings of $606 million.

Expenditures for property exploration, development, and leasehold acquisition costs were as follows:

The information in this Quarterly Report on Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or

anticipates (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," "may," "will," "could," "should," "future," "potential," "continue," variations of such words, and similar expressions identify 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.

These 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. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included or incorporated in Part I of our 2009 Annual Report on Form 10-K and the risks described in Part II, Item 1A, "Risk Factors," in this Form 10-Q.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q 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 Forest 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 persons acting on our behalf may issue.

In addition to reporting net earnings as defined under GAAP, Forest also presents adjusted earnings before interest, income taxes, depreciation, depletion, and amortization ("Adjusted EBITDA"), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings (loss) before interest expense, income taxes, depreciation, depletion, and amortization, as well as other items such as ceiling test write-downs of oil and gas properties, unrealized losses (gains) on derivative instruments, unrealized and realized foreign currency exchange losses (gains), unrealized losses on other investments, accretion of asset retirement obligations, and other items presented in the table below. Adjusted EBITDA does not represent and should not be considered an alternative to GAAP measurements, such as net earnings (loss) (its most comparable GAAP financial measure), and Forest's calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating interest, income taxes, depreciation, depletion, amortization, and other items, Forest believes the result is a useful measure across time in evaluating its fundamental core operating performance. Management also uses Adjusted EBITDA to manage its business, including in preparing its annual operating budget and financial projections. Forest believes that Adjusted EBITDA is also useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. As indicated, Adjusted EBITDA does not include interest expense on borrowed money or depletion and depreciation expense on capital assets or the payment of income taxes, which are necessary elements of Forest's operations. Because Adjusted EBITDA does not account for these and other expenses, its utility as a measure of Forest's operating performance has material limitations. Because of these limitations, Forest's management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) and revenues to measure operating performance. The following table provides a reconciliation of net earnings (loss), the most directly comparable GAAP measure, to Adjusted EBITDA for the periods presented.

In addition to reporting cash provided by operating activities as defined under GAAP, Forest also presents adjusted discretionary cash flow, which is a non-GAAP liquidity measure. Adjusted discretionary cash flow consists of cash provided by operating activities before changes in working capital items. Management uses adjusted discretionary cash flow as a measure of liquidity and believes

it provides useful information to investors because it assesses cash flow from operations for each period before changes in working capital, which fluctuates due to the timing of collections of receivables and the settlements of liabilities. This measure does not represent the residual cash flow available for discretionary expenditures, since Forest has mandatory debt service requirements and other non-discretionary expenditures that are not deducted from the measure. The following table provides a reconciliation of cash provided by operating activities, the most directly comparable GAAP measure, to adjusted discretionary cash flow for the periods presented.

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, basis swaps, and other derivative instruments with counterparties who, in general, are participants in our credit facilities. These arrangements, which are typically 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 effectively 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 June 30, 2010, we had entered into the following swaps:

Subsequent to June 30, 2010, through August 3, 2010, we entered into three additional gas swaps covering 35 Bbtu per day for Calendar 2011 for a weighted average hedged price of $5.61 per MMBtu. In connection with these swaps, we granted commodity swaptions, which expire in December 2010, that enable the counterparties to exercise options to double the Bbtu per day on the gas swaps covering 20 Bbtu per day at a weighted average hedged price of $5.51 per MMBtu and granted a $90.00 per Bbl call option on 1,000 barrels of oil per day for Calendar 2011. See "Commodity Swaptions" below for further discussion of our outstanding commodity swaptions.

We also enter into 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 June 30, 2010, we had entered into the following collars:

In connection with several new gas swaps entered into during the second quarter of 2010, we also entered into commodity swaptions that enable the counterparties to exercise options to either enter into commodity swaps or increase the Bbtu per day on certain existing swaps, as the case may be, with us in exchange for us receiving premium hedged prices on the commodity swaps. During the three months ended June 30, 2010, we entered into gas swaps covering 45 Bbtu per day for Calendar 2011 at a weighted average hedged price of $6.02 per MMBtu. In connection with these swaps, the counterparties were granted the following commodity swaptions, which were outstanding as of June 30, 2010.

Subsequent to June 30, 2010, through August 3, 2010, we entered into additional gas swaptions and an oil call option. See "Swaps" above for further discussion.

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 a portion of our natural gas production is sold. As of June 30, 2010, we had entered into the following basis swaps:

The estimated fair value of all our commodity derivative instruments based on various inputs, including published forward prices, at June 30, 2010 was a net asset of approximately $49.2 million.

We periodically enter into interest rate derivative agreements in an attempt to manage the mix of fixed and floating interest rates within our debt portfolio. As of June 30, 2010, we had entered into the following interest rate swaps:

In addition to the interest rate swaps, we periodically enter into interest rate swaptions that enable the counterparties to exercise options to enter into interest rate swaps with us in exchange for premiums paid to us. The premiums received on these swaptions are amortized as realized gains on derivatives over the terms of the related swaptions. We entered into these interest rate swaptions because our targeted floating interest rates were not attainable at the 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 June 30, 2010.

The estimated fair value of all our interest rate derivative instruments was a net asset of approximately $18.4 million as of June 30, 2010.

The table below sets forth the changes that occurred in the fair values of our open derivative contracts during the six months ended June 30, 2010, beginning with the fair value of our derivative contracts on December 31, 2009. It has been our experience that commodity prices are subject to large

fluctuations, and we expect this volatility to continue. 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. Actual gains and losses recognized related to our commodity derivative instruments will likely differ from those estimated at June 30, 2010 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 Forest's debt obligations at June 30, 2010.

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, Michael N. Kennedy, 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 June 30, 2010 (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 June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

The following risk factor updates the Risk Factors included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 ("Annual Report"). Except as set forth below, there have been no material changes to the risks described in Part I, Item 1A, of the Annual Report.

The enactment of financial reform legislation could have an adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which will, among other things, impose new requirements and oversight on derivatives transactions, including new clearing and margin requirements. Significant regulations are required to be promulgated by the SEC and Commodity Futures Trading Commission to implement these requirements. The new requirements, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to hedge and otherwise manage our financial and commercial risks related to fluctuations in oil and gas commodity prices and interest rates, and could have an adverse effect on our ability to hedge risks associated with our business.

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 second quarter 2010. 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.

Basis Swaps

Remaining Swap Term	Index	Bbtu Per Day		Weighted Average Hedged Price Differential per MMBtu
July 2010 - December 2010	Centerpoint		30	$	(.95	)
July 2010 - December 2010	Houston Ship Channel		50		(.29	)
July 2010 - December 2010	Mid Continent		60		(1.04	)
July 2010 - December 2010	NGPL TXOK		40		(.44	)

Interest Rate Swaps

Remaining Swap Term	Notional Amount (In Thousands)		Weighted Average Floating Rate	Weighted Average Fixed Rate
July 2010 - February 2014	$	500,000	1 month LIBOR + 5.89%		8.50	%

Interest Rate Swaption

Option Term	Underlying Swap Term	Premium Received (In Thousands)		Underlying Swap Notional Amount (In Thousands)		Underlying Swap Floating Rate	Underlying Swap Fixed Rate
April 2010 - Aug 2010	Aug 2010 - Feb 2014	$	634	$	100,000	3 month LIBOR + 5.75%		8.50	%

		Three Months Ended June 30,						Six Months Ended June 30,

		2010			2009			2010			2009
		(In Thousands)
Commodity derivatives:
	Realized (gains)	$	(31,215	)		(84,843	)		(37,663	)		(156,108	)
	Unrealized losses (gains)		25,005			113,399			(54,617	)		47,615
Interest rate derivatives:
	Realized (gains)		(3,310	)		(2,893	)		(6,831	)		(3,417	)
	Unrealized (gains) losses		(15,511	)		7,118			(19,131	)		5,363

Realized and unrealized (gains) losses on derivative instruments, net		$	(25,031	)		32,781			(118,242	)		(106,547	)

	Three Months Ended June 30,					Six Months Ended June 30,

	2010		2009			2010			2009
	(In Thousands)
Federal income tax at 35% of earnings (loss) before income taxes	$	19,009		(10,102	)		78,010			(523,944	)
Change in valuation allowance for deferred tax assets		512		(52,680	)		(178	)		163,157
State income taxes, net of federal income tax benefits		634		(413	)		2,306			(14,657	)
Effect of differing tax rates in Canada		175		(463	)		(1,154	)		11,875
Effect of federal, state, and foreign tax on permanent items		712		(977	)		2,037			2,143
Adjustments for statutory rate reductions and other		16		(1,368	)		(552	)		5,076

Total income tax	$	21,058		(66,003	)		80,469			(356,350	)

		Oil and Gas Exploration and Production

		Three Months Ended June 30, 2010									Six Months Ended June 30, 2010
		United States		Canada		International			Total Company		United States		Canada		International			Total Company
		(In Thousands)
Oil and gas sales		$	169,699		38,255		—			207,954		354,021		75,662		—			429,683
Costs and expenses:
	Lease operating expenses		22,479		5,943		—			28,422		45,947		11,577		—			57,524
	Production and property taxes		11,862		625		—			12,487		22,668		1,247		—			23,915
	Transportation and processing costs		3,271		2,749		—			6,020		5,926		4,953		—			10,879
	Depletion		43,919		16,216		—			60,135		80,430		29,332		—			109,762
	Accretion of asset retirement obligations		1,627		258		24			1,909		3,176		523		49			3,748

Segment earnings (loss)		$	86,541		12,464		(24	)		98,981		195,874		28,030		(49	)		223,855

Capital expenditures⁽¹⁾		$	164,270		52,240		991			217,501		330,766		159,881		2,105			492,752

Goodwill⁽²⁾		$	239,420		16,276		—			255,696		239,420		16,276		—			255,696

Long-lived assets⁽²⁾⁽³⁾		$	1,879,893		548,632		89,095			2,517,620		1,879,893		548,632		89,095			2,517,620

Total assets⁽²⁾		$	2,938,736		622,162		89,878			3,650,776		2,938,736		622,162		89,878			3,650,776

	Three Months Ended June 30, 2010

	(In Thousands)
Segment earnings	$	98,981		223,855
Interest and other income		141		277
General and administrative expense		(17,781	)	(36,534	)
Depreciation and amortization expense		(2,311	)	(4,996	)
Interest expense		(37,109	)	(75,152	)
Realized and unrealized gains on derivative instruments, net		25,031		118,242
Other, net		(12,640	)	(2,807	)

Earnings before income taxes	$	54,312		222,885

		Oil and Gas Exploration and Production

		Three Months Ended June 30, 2009									Six Months Ended June 30, 2009
		United States		Canada		International			Total Company		United States			Canada			International			Total Company
		(In Thousands)
Oil and gas sales		$	154,196		27,434		—			181,630		320,548			55,741			—			376,289
Costs and expenses:
	Lease operating expenses		30,166		7,870		—			38,036		64,868			14,399			—			79,267
	Production and property taxes		10,974		817		—			11,791		21,918			1,568			—			23,486
	Transportation and processing costs		3,346		1,976		—			5,322		6,385			4,181			—			10,566
	Depletion		52,051		13,013		—			65,064		138,542			28,691			—			167,233
	Ceiling test write-down of oil and gas properties		—		—		—			—		1,376,822			199,021			—			1,575,843
	Accretion of asset retirement obligations		1,888		231		24			2,143		3,660			474			47			4,181

Segment earnings (loss)		$	55,771		3,527		(24	)		59,274		(1,291,647	)		(192,593	)		(47	)		(1,484,287	)

Capital expenditures⁽¹⁾		$	84,700		6,816		1,272			92,788		310,560			32,792			2,237			345,589

Goodwill⁽²⁾		$	239,420		14,899		—			254,319		239,420			14,899			—			254,319

Long-lived assets⁽²⁾⁽³⁾		$	2,542,658		491,426		79,569			3,113,653		2,542,658			491,426			79,569			3,113,653

Total assets⁽²⁾		$	3,389,041		503,010		80,327			3,972,378		3,389,041			503,010			80,327			3,972,378

			June 30, 2010													December 31, 2009

			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		$	200,163		1			622			—			200,786		456,978		379			9,864			—			467,221
	Accounts receivable			46,808		36,050			37,707			(448	)		120,117		79,857		24,406			22,671			(580	)		126,354
	Deferred income taxes			—		—			—			—			—		6,589		519			—			—			7,108
	Other current assets			132,279		774			19,415			—			152,468		115,663		797			12,849			—			129,309

		Total current assets		379,250		36,825			57,744			(448	)		473,371		659,087		26,101			45,384			(580	)		729,992
Property and equipment, at cost				7,273,707		1,134,625			1,769,843			—			10,178,175		7,093,082		1,074,610			1,657,986			—			9,825,678
	Less accumulated depreciation, depletion, and amortization			5,558,455		1,014,910			1,087,190			—			7,660,555		5,502,530		994,005			1,069,936			—			7,566,471

		Net property and equipment		1,715,252		119,715			682,653			—			2,517,620		1,590,552		80,605			588,050			—			2,259,207
Investment in subsidiaries				333,224		—			—			(333,224	)		—		308,424		—			—			(308,424	)		—
Note receivable from subsidiary				224,306		—			—			(224,306	)		—		135,529		—			—			(135,529	)		—
Goodwill				216,460		22,960			16,276			—			255,696		216,460		22,960			16,488			—			255,908
Due from (to) parent and subsidiaries				238,555		(54,920	)		(183,635	)		—			—		215,679		(60,884	)		(154,795	)		—			—
Deferred income taxes				359,885		—			—			(13,751	)		346,134		395,519		—			—			(2,458	)		393,061
Other assets				55,712		6			2,237			—			57,955		44,087		6			2,429			—			46,522

			$	3,522,644		124,586			575,275			(571,729	)		3,650,776		3,565,337		68,788			497,556			(446,991	)		3,684,690

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable and accrued liabilities		$	222,327		2,682			35,784			(448	)		260,345		238,935		6,825			39,122			(580	)		284,302
	Current portion of long-term-debt			—		—			—			—			—		156,678		—			—			—			156,678
	Other current liabilities			75,385		—			6,502			—			81,887		86,633		64			7,343			—			94,040

		Total current liabilities		297,712		2,682			42,286			(448	)		342,232		482,246		6,889			46,465			(580	)		535,020
Long-term debt				1,867,534		—			—			—			1,867,534		1,865,836		—			—			—			1,865,836
Note payable to parent				—		—			224,306			(224,306	)		—		—		—			135,529			(135,529	)		—
Other liabilities				123,760		2,309			30,751			—			156,820		121,869		769			35,158			—			157,796
Deferred income taxes				—		33,360			30,943			(13,751	)		50,552		16,232		4,446			28,664			(2,458	)		46,884

		Total liabilities		2,289,006		38,351			328,286			(238,505	)		2,417,138		2,486,183		12,104			245,816			(138,567	)		2,605,536
Shareholders' equity				1,233,638		86,235			246,989			(333,224	)		1,233,638		1,079,154		56,684			251,740			(308,424	)		1,079,154

			$	3,522,644		124,586			575,275			(571,729	)		3,650,776		3,565,337		68,788			497,556			(446,991	)		3,684,690

		Three Months Ended June 30,

		2010								2009
		Gas		Oil		NGLs		Total		Gas		Oil		NGLs		Total
		(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(MMcf)		(MBbls)		(MBbls)		(MMcfe)
Production volumes:
	United States		25,997		635		855		34,937		30,076		879		782		40,042
	Canada		5,547		251		32		7,245		6,032		163		57		7,352

Totals			31,544		886		887		42,182		36,108		1,042		839		47,394

Revenues (in thousands):
	United States	$	96,751		46,562		26,386		169,699		87,333		48,957		17,906		154,196
	Canada		19,811		16,717		1,727		38,255		17,235		8,585		1,614		27,434

Totals		$	116,562		63,279		28,113		207,954		104,568		57,542		19,520		181,630

Average sales price per unit:
	United States	$	3.72		73.33		30.86		4.86		2.90		55.70		22.90		3.85
	Canada		3.57		66.60		53.97		5.28		2.86		52.67		28.32		3.73

Totals		$	3.70		71.42		31.69		4.93		2.90		55.22		23.27		3.83

Oil Collars (NYMEX WTI)

Remaining Collar Term	Barrels Per Day		Weighted Average Hedged Floor and Ceiling Price per Bbl		Fair Value (In Thousands)
July 2010 - December 2010		2,000	$	60.00/98.50	$	96
Calendar 2011		3,000		75.00/91.87		2,688

Interest Rate Swaption

Option Term	Swap Term		Premium Received (In Thousands)		Notional Amount (In Thousands)		Floating Rate	Fixed Rate			Fair Value (In Thousands)
April 2010 - Aug 2010		Aug 2010 - Feb 2014	$	634	$	100,000	3 month LIBOR + 5.75%		8.50	%	$	(5	)

	Fair Value of Derivative Contracts

	Commodity			Interest Rate			Total
	(In Thousands)
As of December 31, 2009	$	(5,389	)		(596	)		(5,985	)
Premiums received		—			(984	)		(984	)
Net increase in fair value		92,281			26,794			119,075
Net contract gains realized		(37,663	)		(6,831	)		(44,494	)

As of June 30, 2010	$	49,229			18,383			67,612

		2011

		(Dollar Amounts in Thousands)
Long-term debt:
	Fixed rate debt	$	285,000		12		600,000		1,000,000		1,885,012
	Coupon interest rate		8.00	%	7.00	%	8.50	%	7.25	%	7.76	%
	Effective interest rate⁽¹⁾		7.25	%	7.49	%	9.47	%	7.24	%	7.95	%

Period		Average Price Paid Per Share

April 2010	—	$	—	—	—
May 2010	—		—	—	—
June 2010	172,348		30.63	—	—

Second Quarter Total	172,348	$	30.63	—	—

				Six Months Ended June 30,

				2010															2009
				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			$	259,204			93,495			76,984			—			429,683			255,777			63,677			56,835			—			376,289
	Interest and other				2,767			9			9			(2,508	)		277			6,818			91			(35	)		(6,230	)		644
	Equity earnings (losses) in subsidiaries				59,253			—			—			(59,253	)		—			(294,297	)		—			—			294,297			—

			Total revenues		321,224			93,504			76,993			(61,761	)		429,960			(31,702	)		63,768			56,800			288,067			376,933
Costs, expenses, and other:
	Lease operating expenses				40,117			5,626			11,781			—			57,524			53,690			10,738			14,839			—			79,267
	Other direct operating costs				23,118			6,229			5,447			—			34,794			25,915			3,474			4,663			—			34,052
	General and administrative				30,060			1,163			5,311			—			36,534			26,473			1,327			3,934			—			31,734
	Depreciation, depletion, and amortization				63,490			20,905			30,363			—			114,758			117,763			28,471			26,455			—			172,689
	Ceiling test write-down of oil and gas properties				—			—			—			—			—			1,155,777			218,567			201,499			—			1,575,843
	Interest expense				72,634			1,078			3,948			(2,508	)		75,152			71,279			4,821			9,850			(6,230	)		79,720
	Realized and unrealized gains on derivative instruments, net				(98,061	)		(19,941	)		(240	)		—			(118,242	)		(87,192	)		(19,079	)		(276	)		—			(106,547	)
	Other, net				(1,127	)		32			7.650			—			6,555			5,942			141			1,074			—			7,157

		Total costs, expenses, and other			130,231			15,092			64,260			(2,508	)		207,075			1,369,647			248,460			262,038			(6,230	)		1,873,915

Earnings (loss) before income taxes					190,993			78,412			12,733			(59,253	)		222,885			(1,401,349	)		(184,692	)		(205,238	)		294,297			(1,496,982	)
		Income tax			48,577			28,918			2,974			—			80,469			(260,717	)		(43,606	)		(52,027	)		—			(356,350	)

Net earnings (loss)				$	142,416			49,494			9,759			(59,253	)		142,416			(1,140,632	)		(141,086	)		(153,211	)		294,297			(1,140,632	)

		Six Months Ended June 30,

		2010								2009
		Gas		Oil		NGLs		Total		Gas		Oil		NGLs		Total
		(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(MMcf)		(MBbls)		(MBbls)		(MMcfe)
Production volumes:
	United States		50,104		1,137		1,532		66,118		62,196		1,816		1,592		82,644
	Canada		10,526		431		79		13,586		11,500		331		121		14,212

Totals			60,630		1,568		1,611		79,704		73,696		2,147		1,713		96,856

Revenues (in thousands):
	United States	$	215,846		84,675		53,500		354,021		202,938		84,057		33,553		320,548
	Canada		42,545		29,192		3,925		75,662		38,076		14,245		3,420		55,741

Totals		$	258,391		113,867		57,425		429,683		241,014		98,302		36,973		376,289

Average sales price per unit:
	United States	$	4.31		74.47		34.92		5.35		3.26		46.29		21.08		3.88
	Canada		4.04		67.73		49.68		5.57		3.31		43.04		28.26		3.92

Totals		$	4.26		72.62		35.65		5.39		3.27		45.79		21.58		3.89


	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		Amendment No. 2 to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 12, 2010 (File No. 001-13515).
	10.2		Severance Agreement, dated as of December 1, 2009, by and between Victor A. Wind and Forest Oil Corporation, incorporated herein by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation dated May 11, 2010 (File No. 001-13515).
	10.3		Form of Performance Unit Award Agreement (US) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 21, 2010 (File No. 001-13515).
	10.4		Form of Performance Unit Award Agreement (Canada) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation dated May 21, 2010 (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 Principal Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
	32.2⁺		Certification of Principal 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.


	FOREST OIL CORPORATION (Registrant)
August 6, 2010	By:	/s/ MICHAEL N. KENNEDY Michael N. Kennedy 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 Senior Vice President, Chief Accounting Officer and Corporate Controller (Principal Accounting Officer)