Edgar Filing: FOREST OIL CORP

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

FORM 10-Q


(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 October 29, 2010 there were 113,383,660 shares of the registrant's common stock, par value $.10 per share, outstanding.

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FOREST OIL CORPORATION
INDEX TO FORM 10-Q
September 30, 2010


Part I—FINANCIAL INFORMATION			1
	Item 1—Financial Statements		1
		Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009	1
		Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009	2
		Condensed Consolidated Statement of Shareholders' Equity for the Nine Months Ended September 30, 2010	3
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 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		28
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		41
	Item 4—Controls and Procedures		44
Part II—OTHER INFORMATION			46
	Item 1A.—Risk Factors		46
	Item 2—Unregistered Sales of Equity Securities and Use of Proceeds		46
	Item 6—Exhibits		47
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)

				September 30, 2010

ASSETS
Current assets:
	Cash and cash equivalents			$	251,599		467,221
	Accounts receivable				102,709		126,354
	Derivative instruments				91,784		35,643
	Deferred income taxes				—		7,108
	Inventory				40,445		52,211
	Other current assets				50,858		41,455

		Total current assets			537,395		729,992
Property and equipment, at cost:
	Oil and gas properties, full cost method of accounting:
		Proved, net of accumulated depletion of $7,706,181 and $7,511,661			1,725,430		1,316,712
		Unproved			808,220		828,645

			Net oil and gas properties		2,533,650		2,145,357
	Other property and equipment, net of accumulated depreciation and amortization of $47,864 and $54,810				81,645		113,850

			Net property and equipment		2,615,295		2,259,207
Deferred income taxes					301,940		393,061
Goodwill					256,259		255,908
Derivative instruments					24,251		556
Other assets					40,290		45,966

				$	3,775,430		3,684,690

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable and accrued liabilities			$	271,644		284,302
	Accrued interest				34,705		25,755
	Derivative instruments				14,071		41,358
	Deferred income taxes				25,840		—
	Current portion of long-term debt				—		156,678
	Asset retirement obligations				1,690		4,853
	Other current liabilities				21,498		22,074

		Total current liabilities			369,448		535,020
Long-term debt					1,868,453		1,865,836
Asset retirement obligations					85,871		88,450
Derivative instruments					5,034		826
Deferred income taxes					54,329		46,884
Other liabilities					73,166		68,520

	Total liabilities				2,456,301		2,605,536
Shareholders' equity:
	Preferred stock, none issued and outstanding				—		—
	Common stock, 113,359,349 and 112,337,315 shares issued and outstanding				11,336		11,234
	Capital surplus				2,675,128		2,652,689
	Accumulated deficit				(1,441,099	)	(1,652,426	)
	Accumulated other comprehensive income				73,764		67,657

	Total shareholders' equity				1,319,129		1,079,154

				$	3,775,430		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 September 30,						Nine Months Ended September 30,

			2010			2009			2010			2009
Revenues:
	Oil and gas sales		$	210,181			177,184			639,864			553,473
	Interest and other			206			(42	)		483			602

Total revenues				210,387			177,142			640,347			554,075
Costs, expenses, and other:
	Lease operating expenses			30,177			34,938			87,701			114,205
	Production and property taxes			13,376			10,873			37,291			34,359
	Transportation and processing costs			6,210			5,352			17,089			15,918
	General and administrative			18,007			17,316			54,541			49,050
	Depreciation, depletion, and amortization			64,737			65,275			179,495			237,964
	Ceiling test write-down of oil and gas properties			—			—			—			1,575,843
	Interest expense			37,088			42,653			112,240			122,373
	Realized and unrealized gains on derivative instruments, net			(59,156	)		(5,665	)		(177,398	)		(112,212	)
	Other, net			(6,396	)		(2,060	)		159			5,097

		Total costs, expenses, and other		104,043			168,682			311,118			2,042,597
Earnings (loss) before income taxes				106,344			8,460			329,229			(1,488,522	)
Income tax:
	Current			(16,814	)		—			(12,089	)		1,505
	Deferred			54,247			(163,851	)		129,991			(521,706	)

		Total income tax		37,433			(163,851	)		117,902			(520,201	)

Net earnings (loss)			$	68,911			172,311			211,327			(968,321	)

Basic earnings (loss) per common share			$	.61			1.53			1.87			(9.46	)

Diluted earnings (loss) per common share			$	.60			1.53			1.86			(9.46	)

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		223			22			4,293			—		—		4,315
	Employee stock purchase plan		52			5			1,125			—		—		1,130
	Restricted stock issued, net of cancellations		879			88			(88	)		—		—		—
	Amortization of stock-based compensation		—			—			21,042			—		—		21,042
	Other, net		(132	)		(13	)		(3,933	)		—		—		(3,946	)
Comprehensive earnings:
	Net earnings		—			—			—			211,327		—		211,327
	Unfunded postretirement benefits, net of tax		—			—			—			—		975		975
	Foreign currency translation		—			—			—			—		5,132		5,132

	Total comprehensive earnings															217,434

Balances at September 30, 2010			113,359		$	11,336			2,675,128			(1,441,099	)	73,764		1,319,129

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)

			Nine Months Ended September 30,

			2010			2009
Operating activities:
	Net earnings (loss)		$	211,327			(968,321	)
	Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
		Depreciation, depletion, and amortization		179,495			237,964
		Ceiling test write-down of oil and gas properties		—			1,575,843
		Deferred income tax		129,991			(521,706	)
		Unrealized (gains) losses on derivative instruments, net		(102,839	)		132,216
		Unrealized foreign currency exchange gains, net		(5,290	)		(15,609	)
		Unrealized losses on other investments, net		—			2,327
		Stock-based compensation expense		14,389			12,948
		Accretion of asset retirement obligations		5,441			6,195
		Other, net		1,162			4,201
	Changes in operating assets and liabilities:
		Accounts receivable		24,345			66,143
		Other current assets		1,539			20,622
		Accounts payable and accrued liabilities		(66,123	)		(106,567	)
		Accrued interest and other current liabilities		4,870			27,317

Net cash provided by operating activities				398,307			473,573
Investing activities:
	Capital expenditures for property and equipment:
		Exploration, development, and leasehold acquisition costs		(612,453	)		(512,266	)
		Other fixed assets		(19,831	)		(30,185	)
	Proceeds from sales of assets			156,177			145,691
	Other, net			1,189			—

Net cash used by investing activities				(474,918	)		(396,760	)
Financing activities:
	Proceeds from bank borrowings			101,198			706,551
	Repayments of bank borrowings			(101,198	)		(1,556,174	)
	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			—			256,217
	Proceeds from the exercise of options and from employee stock purchase plan			5,445			1,296
	Change in bank overdrafts			13,852			(36,303	)
	Other, net			(5,934	)		(3,665	)

Net cash used by financing activities				(138,675	)		(73,281	)
Effect of exchange rate changes on cash				(336	)		(584	)

Net (decrease) increase in cash and cash equivalents				(215,622	)		2,948
Cash and cash equivalents at beginning of period				467,221			2,205

Cash and cash equivalents at end of period			$	251,599			5,153

Cash paid during the period for:
	Interest		$	103,819			92,711
	Income taxes			67,641			3,783

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 September 30, 2010 and the results of its operations, its cash flows, and changes in shareholders' equity for the periods presented. 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 (e.g. 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 months ended September 30, 2010 and 2009 and the nine months ended September 30, 2010 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 nine months ended September 30, 2009 as their inclusion would have an antidilutive effect.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

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

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

	2010			2009			2010			2009
	(In Thousands, Except Per Share Amounts)
Net earnings (loss)	$	68,911			172,311			211,327			(968,321	)
Net earnings attributable to participating securities		(1,427	)		(3,384	)		(4,116	)		—

Net earnings (loss) attributable to common stock for basic earnings per share		67,484			168,927			207,211			(968,321	)
Adjustment for liability-classified stock-based compensation awards		74			(21	)		250			—

Net earnings (loss) for diluted earnings per share	$	67,558			168,906			207,461			(968,321	)

Weighted average common shares outstanding during the period for basic earnings per share		110,992			110,054			110,691			102,366
Dilutive effects of potential common shares		786			168			699			—

Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings per share		111,778			110,222			111,390			102,366

Basic earnings (loss) per common share	$	.61			1.53			1.87			(9.46	)

Diluted earnings (loss) per common share	$	.60			1.53			1.86			(9.46	)

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 nine months ended September 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 September 30,				Nine Months Ended September 30,

		2010		2009		2010		2009
		(In Thousands)
Net earnings (loss)		$	68,911		172,311		211,327		(968,321	)
Other comprehensive income:
	Foreign currency translation gains		8,978		18,591		5,132		22,623
	Unfunded postretirement benefits, net of tax		290		316		975		984

Total comprehensive earnings (loss)		$	78,179		191,218		217,434		(944,714	)

(3) STOCK-BASED COMPENSATION

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

		Stock Options

		(In Thousands)
Three months ended September 30, 2010:
	Total stock-based compensation costs	$	166		6,786		1,230		8,182
	Less: stock-based compensation costs capitalized		(73	)	(2,546	)	(588	)	(3,207	)

	Stock-based compensation costs expensed	$	93		4,240		642		4,975

Nine months ended September 30, 2010:
	Total stock-based compensation costs	$	396		20,240		3,759		24,395
	Less: stock-based compensation costs capitalized		(169	)	(7,273	)	(1,720	)	(9,162	)

	Stock-based compensation costs expensed	$	227		12,967		2,039		15,233

Unamortized stock-based compensation costs		$	464		39,151		8,112	⁽³⁾	47,727
Weighted average amortization period remaining			.7 year		2.1 years		2.0 years		2.0 years
Three months ended September 30, 2009:
	Total stock-based compensation costs	$	196		6,938		972		8,106
	Less: stock-based compensation costs capitalized		(70	)	(2,664	)	(470	)	(3,204	)

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

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

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

⁽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 $.4 million of compensation cost was recognized for the three and nine months ended September 30, 2010, respectively, and $.1 million and $.5 million of compensation cost was recognized for the three and nine months ended September 30, 2009, respectively.
⁽³⁾: Based on the closing price of the Company's common stock on September 30, 2010.

Stock Options

The following table summarizes stock option activity in the Company's stock-based compensation plans for the nine months ended September 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	(223,082	)		19.35		1,674
Cancelled	(27,752	)		35.30

Outstanding at September 30, 2010	1,567,585		$	21.29	$	15,672	1,523,122

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

Restricted Stock and Phantom Stock Units

The following table summarizes the restricted stock and phantom stock unit activity in the Company's stock-based compensation plans for the nine months ended September 30, 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		1,253,043			26.04				142,835			25.30
Vested		(566,810	)		39.75	$	17,072		(65,140	)		41.88	$	1,910
Forfeited		(110,020	)		36.15				(52,156	)		35.37

Unvested at September 30, 2010		2,604,896		$	33.07				500,602		$	24.57

⁽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 September 30, 2010, 260,985 units can be settled in cash, shares of common stock, or a combination of both, while the remaining 239,617 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 65,140 phantom stock units that vested during the nine months ended September 30, 2010, 63,750 units were settled in shares of common stock and 1,390 units were settled in cash.

(4) DEBT

The components of debt are as follows:

	September 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		1,615			1,011		287,626		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		(19,677	)		—		580,323		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		492			—		1,000,492		1,000,000			534			—			1,000,534

Total long-term debt		1,885,012		(17,570	)		1,011		1,868,453		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		(17,570	)		1,011		1,868,453		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.

Bank Credit Facilities

As of September 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 September 30, 2010, there were no outstanding borrowings under the Credit Facilities.

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(Unaudited)

(4) DEBT (Continued)

Forest's availability under the Credit Facilities is governed by a borrowing base (the "Global Borrowing Base"). As of September 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 October 2010, the lenders reaffirmed the borrowing base at $1.3 billion and the next redetermination is expected to occur in the second quarter of 2011. 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 September 30, 2010 and 2009, Forest capitalized $12.0 million and $11.4 million of general and administrative costs (including stock-based compensation), respectively. During the nine months ended September 30, 2010 and 2009, Forest capitalized $34.6 million and $33.5 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 September 30, 2010 and 2009, the Company capitalized $3.0 million and $2.5 million, respectively, of interest costs attributed to unproved properties. During the nine months ended September 30, 2010 and 2009, the Company capitalized $8.9 million and $9.3 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 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

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(5) PROPERTY AND EQUIPMENT (Continued)

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 September 30, 2010 ceiling test, which did not result in a write-down, was based on the average of the first-day-of-the-month prices during the twelve-month period prior to September 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 plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(6) ASSET RETIREMENT OBLIGATIONS (Continued)

The following table summarizes the activity for Forest's asset retirement obligations for the nine months ended September 30, 2010 and 2009.

	Nine Months Ended September 30,

	2010			2009
	(In Thousands)
Asset retirement obligations at beginning of period	$	93,303			96,991
Accretion expense		5,441			6,195
Liabilities incurred		2,083			4,676
Liabilities settled		(1,623	)		(2,474	)
Disposition of properties		(7,377	)		(5,283	)
Revisions of estimated liabilities		(4,461	)		(2,494	)
Impact of foreign currency exchange rate		195			1,541

Asset retirement obligations at end of period		87,561			99,152
Less: current asset retirement obligations		(1,690	)		(3,456	)

Long-term asset retirement obligations	$	85,871			95,696

(7) FAIR VALUE MEASUREMENTS

The Company's assets and liabilities measured at fair value on a recurring basis at September 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	$	89,555
		Interest rate		26,480

Total assets			$	116,035

Liabilities:
	Derivative instruments⁽²⁾
		Commodity	$	19,105
		Interest rate		—

Total liabilities			$	19,105

⁽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; 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

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(7) FAIR VALUE MEASUREMENTS (Continued)

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 nine months ended September 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.

		Nine Months Ended September 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 stock exchange listing requirements. The Company used its own assumptions as to what market participants would

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(7) FAIR VALUE MEASUREMENTS (Continued)

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 nine months ended September 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 September 30, 2009.

	Nine Months Ended September 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.

		September 30, 2010				December 31, 2009

		Carrying Amount		Fair Value⁽¹⁾		Carrying Amount		Fair Value⁽¹⁾
		(In Thousands)
Assets:
	Cash and cash equivalents	$	251,599		251,599		467,221		467,221
	Derivative instruments		116,035		116,035		36,199		36,199
Liabilities:
	Derivative instruments		19,105		19,105		42,184		42,184
	8% senior notes due 2011		287,626		300,818		289,221		296,400
	7% senior subordinated notes due 2013		12		12		110		112
	8¹/2% senior notes due 2014		580,323		657,000		575,971		630,000
	7³/4% senior notes due 2014		—		—		156,678		151,938
	7¹/4% senior notes due 2019		1,000,492		1,030,000		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 September 30, 2010.

Commodity Swaps and Collars

		Natural Gas (NYMEX HH)				Oil (NYMEX WTI)					NGLs (OPIS Refined Products)
Remaining Swap Term		Bbtu Per Day		Weighted Average Hedged Price per MMBtu		Barrels Per Day		Weighted Average Hedged Price per Bbl			Barrels Per Day		Weighted Average Hedged Price per Bbl
Swaps:
	October 2010 - December 2010		210	$	6.20		3,000	$	76.06			—	$	—
	Calendar 2011		90		5.86		—		—			3,000		36.75
Collars:
	October 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⁾: Subsequent to September 30, 2010, in connection with receiving a premium hedged price on a gas swap, Forest lowered the hedged ceiling price on one of its existing Calendar 2011 oil collars that covered 1,000 barrels per day from $95.00 to $90.00 per Bbl.

In connection with several gas swaps entered into during the nine months ended September 30, 2010, Forest granted option instruments (several commodity swaptions and one call option) to the gas swap counterparties in exchange for Forest receiving premium hedged prices on the gas swaps. As of October 29, 2010, none of the options have been exercised by the counterparties. The table below sets forth the outstanding options as of September 30, 2010.

Commodity Options

			Natural Gas (NYMEX HH)				Oil (NYMEX WTI)
Instrument	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
Gas Swaptions	December 2010	Calendar 2011		50	$	5.80		—	$	—
Oil Swaption	December 2011	Calendar 2012		—		—		1,000		90.00
Oil Call Option	Monthly in 2011	Monthly in 2011		—		—		1,000		90.00

Subsequent to September 30, 2010, through October 29, 2010, Forest entered into two additional gas swaps covering 25 Bbtu per day for Calendar 2011 for a weighted average hedged price of $5.03

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(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

per MMBtu. In connection with these swaps, the counterparties were granted the following oil swaptions.

Commodity Options

		Oil (NYMEX WTI)
Option Expiration	Underlying Swap Term	Underlying Swap Barrels Per Day		Underlying Swap Hedged Price per Bbl
December 2010	Calendar 2011		1,000	$	85.00
December 2011	Calendar 2012		1,000		90.00

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 September 30, 2010.

Basis Swaps

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

Interest Rate Derivatives

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 September 30, 2010.

Interest Rate Swaps

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

Fair Value and Gains and Losses

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

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(8) DERIVATIVE INSTRUMENTS (Continued)

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.

			September 30, 2010

			(In Thousands)
Assets:
	Commodity derivatives:
		Current assets: derivative instruments	$	80,870	35,454
		Derivative instruments		8,685	—
	Interest rate derivatives:
		Current assets: derivative instruments		10,914	189
		Derivative instruments		15,566	556

Total assets				116,035	36,199
Liabilities:
	Commodity derivatives:
		Current liabilities: derivative instruments		14,071	40,843
		Derivative instruments		5,034	—
	Interest rate derivatives:
		Current liabilities: derivative instruments		—	515
		Derivative instruments		—	826

Total liabilities				19,105	42,184

Net derivative fair value			$	96,930	(5,985	)

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

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

		2010			2009			2010			2009
		(In Thousands)
Commodity derivatives:
	Realized gains	$	(27,153	)		(81,395	)		(64,816	)		(237,503	)
	Unrealized (gains) losses		(21,222	)		87,857			(75,839	)		135,472
Interest rate derivatives:
	Realized gains		(2,912	)		(3,508	)		(9,743	)		(6,925	)
	Unrealized gains		(7,869	)		(8,619	)		(27,000	)		(3,256	)

Realized and unrealized gains on derivative instruments, net		$	(59,156	)		(5,665	)		(177,398	)		(112,212	)

Due to the volatility of natural gas and liquids prices, the estimated fair values of Forest's commodity derivative instruments are subject to large fluctuations from period to period. Forest has

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(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

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.

Credit Risk

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 Forest, the fair value of which was $98.1 million at September 30, 2010. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to

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(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

notification periods, of the net obligations due to it under the derivative agreements. At September 30, 2010, Forest owed a net derivative liability to two counterparties, the fair value of which was $1.2 million.

(9) INCOME TAXES

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

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

	2010			2009			2010			2009
	(In Thousands)
Federal income tax at 35% of earnings (loss) before income taxes	$	37,220			2,961			115,230			(520,983	)
Change in valuation allowance for deferred tax assets		(980	)		(163,858	)		(1,158	)		(701	)
State income taxes, net of federal income tax benefits		1,038			(538	)		3,344			(15,195	)
Effect of differing tax rates in Canada		(942	)		(374	)		(2,096	)		11,501
Effect of federal, state, and foreign tax on permanent items		1,488			(848	)		3,525			1,295
Adjustments for statutory rate reductions and other		(391	)		(1,194	)		(943	)		3,882

Total income tax	$	37,433			(163,851	)		117,902			(520,201	)

As of September 30, 2010, the Company had $17.6 million due from the United States Treasury Department, which is included in "Other current assets" in the Condensed Consolidated Balance Sheet, related to estimated tax payments made in excess of the Company's 2009 income tax liability.

(10) COSTS, EXPENSES, AND OTHER

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

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

	2010			2009			2010			2009
	(In Thousands)
Unrealized foreign currency exchange gains, net	$	(9,244	)		(9,723	)		(5,290	)		(15,609	)
Unrealized losses on other investments, net		—			—			—			2,327
Accretion of asset retirement obligations		1,693			2,014			5,441			6,195
Gain on debt extinguishment, net		—			—			(4,576	)		—
Other, net		1,155			5,649			4,584			12,184

	$	(6,396	)		(2,060	)		159			5,097

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

At September 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 earnings (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 September 30, 2010 and December 31, 2009 and for the nine months ended September 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 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 third quarter and year-to-date 2010 highlights and other significant items were as follows:

Forest reported net earnings of $69 million in the third quarter of 2010, or $.60 per diluted share, compared to net earnings of $172 million, or $1.53 per diluted share, in the third quarter 2009. The decrease in net earnings in the third quarter 2010 compared to the third quarter 2009 was primarily due to a $164 million reduction of a valuation allowance on a portion of our deferred tax assets during the third quarter 2009. Earnings before income taxes increased $98 million between the two quarterly periods due to increased commodity prices and an increase in net realized and unrealized gains on commodity derivative instruments. Forest reported net earnings of $211 million in the first nine months of 2010, or $1.86 per diluted share, compared to a net loss of $968 million, or $9.46 per diluted share, in the first nine months of 2009. The increase in net earnings in the first nine 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, as well as due to increased commodity prices and an increase in net realized and unrealized gains on commodity derivative instruments.

Forest's earnings before interest expense; income taxes; depletion, depreciation, and amortization expense; and certain other items ("Adjusted EBITDA"), were $176 million and $193 million for the quarters ended September 30, 2010 and 2009, respectively, and were $528 million and $586 million for the first nine months of 2010 and 2009, respectively. The decrease in Adjusted EBITDA in the 2010 periods as compared to the 2009 periods is primarily driven by decreases in realized gains on derivative instruments somewhat offset by increases in revenues and lower production expense, 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 nine months ended September 30, 2010 and 2009 are set forth in the tables below.

Net oil and gas production in the third quarter 2010 decreased 4% to 457 MMcfe per day from 476 MMcfe per day in the third quarter 2009. Net oil and gas production in the first nine months of 2010 decreased 13% to 446 MMcfe per day from 515 MMcfe per day in the first nine months of 2009. The decrease in oil and gas production for the comparable three and nine month periods was due to non-core oil and gas property divestitures that occurred primarily in late 2009. Oil and gas revenues were $210 million in the third quarter 2010, a 19% increase as compared to $177 million in the third quarter 2009. Oil and gas revenues were $640 million in the first nine months of 2010, a 16% increase as compared to $553 million in the first nine months of 2009. The increase in oil and gas revenues between the comparable three and nine month periods was primarily due to a 23% and 33% 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 nine months ended September 30, 2010 and 2009.

Lease operating expenses in the third quarter 2010 were $30 million, or $.72 per Mcfe, compared to $35 million, or $.80 per Mcfe, in the third quarter 2009. Lease operating expenses in the first nine months of 2010 were $88 million, or $.72 per Mcfe, compared to $114 million, or $.81 per Mcfe, in the first nine months of 2009. The $5 million and $27 million decrease in lease operating expense between the comparable three and nine 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 6.4% and 6.1% for the three months ended September 30, 2010 and 2009, respectively, and 5.8% and 6.2% for the nine months ended September 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 third quarter 2010 were $6 million, or $.15 per Mcfe, compared to $5 million, or $.12 per Mcfe, in the third quarter 2009. Transportation and processing costs in the first nine months of 2010 were $17 million, or $.14 per Mcfe, compared to $16 million, or $.11 per Mcfe, in the first nine months of 2009. Transportation and processing costs increased between comparable periods primarily due to higher transportation costs in Canada.

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

General and administrative expense in the third quarter 2010 was $18 million compared to $17 million in the third quarter 2009. General and administrative expense in the first nine months of 2010 was $55 million compared to $49 million in the first nine months of 2009. The increase in general and administrative expense between the nine month periods was primarily due to higher employee incentive compensation costs, including stock-based incentive compensation. 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 39% to 41%.

Depreciation, depletion, and amortization expense ("DD&A") in the third quarter 2010 was $65 million, or $1.54 per Mcfe, compared to $65 million, or $1.49 per Mcfe, in the third quarter 2009. For the nine months ended September 30, 2010, DD&A was $179 million, or $1.47 per Mcfe, compared to $238 million, or $1.69 per Mcfe, for the first nine months of 2009. The decrease of $.22

per Mcfe between the nine-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. We have not incurred a ceiling test write-down since March 31, 2009. Our ceiling test calculations have been calculated based on the twelve month average natural gas and oil prices since December 31, 2009.

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

Interest expense in the third quarter 2010 totaled $37 million compared to $43 million in the third quarter 2009. Interest expense was $112 million and $122 million for the nine months ended September 30, 2010 and 2009, respectively. Although our outstanding debt decreased to $1.9 billion as of September 30, 2010 from $2.5 billion as of September 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 nine 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 September 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 $9 million during the three and nine months ended September 30, 2010, respectively, and $3 million during both the three and nine months ended September 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 net gain on debt extinguishment for the nine months ended September 30, 2010 includes the 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. This gain is offset by the loss on debt extinguishment related 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 second quarter of 2010 at par. 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 35% to 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 35% and 36% for the three and nine months ended September 30, 2010, respectively, and (1,937)% and 35% for the three and nine months ended September 30, 2009, respectively. The significant variance in our effective tax rate for the three months ended September 30, 2009 was due to the valuation allowance placed on a portion of our deferred tax assets in the United States during that period. 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. The current income tax credit of $16.8 million and $12.1 million for the three and nine months ended September 30, 2010 is due to a $17.0 million reduction in our 2009 federal income tax liability recorded in the third quarter of 2010.

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 nine months ended September 30, 2010, natural gas accounted for approximately 75% 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 October 29, 2010, we had hedged, via commodity swaps and collar instruments, approximately 86 Bcfe of our total 2010 production and 55 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 September 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 September 30, 2010 and October 29, 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 economic 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 nine months of 2010 we have sold additional non-strategic assets for total proceeds of $156 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, including the redemption of our $285 million principal amount of senior notes that are due in December 2011. 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 September 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 October 2010, the lenders reaffirmed the borrowing base at $1.3 billion and the next redetermination is expected to occur in the second quarter of 2011. 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 September 30, 2010 and October 29, 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 September 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 October 29, 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 40 Bcfe, or 73% 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 by financing activities for the nine months ended September 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 nine months ended September 30, 2010 compared to the same period of 2009 was primarily due to lower realized gains on our derivative contracts and an increased investment in net operating assets (i.e., working capital) offset somewhat by higher average realized prices for oil and gas. 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 $417 million and $466 million for the nine months ended September 30, 2010 and 2009, respectively. The decrease in adjusted discretionary cash flow between the nine-month periods was primarily driven by a decrease in realized gains on oil and gas derivative instruments of $173 million offset by an increase in oil and gas revenues of $86 million and a decrease in production and interest expenses of $22 million and $10 million, respectively. 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 and other capital assets. The increase in net cash used by investing activities in the nine months ended September 30, 2010 compared to the same period of 2009 was primarily due to increased exploration, development, and leasehold acquisition costs during the nine months ended September 30, 2010 as compared to the same period of 2009. The major components of cash used by investing activities for the nine months ended September 30, 2010 and 2009 were as follows:

Net cash used by financing activities in the nine months ended September 30, 2010 included the redemption of the 7³/4% senior notes for $152 million. Net cash used by financing activities in the nine months ended September 30, 2009 included net repayments of bank borrowings of $850 million, partially offset by net proceeds of $560 million for the issuance of the 8¹/2% senior notes and net proceeds of $256 million for the issuance of common stock.

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, as well as the risks described in Part II, Item 1A, "Risk Factors," in our Form 10-Q for the quarter ended June 30, 2010, and 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 a commodity 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 September 30, 2010, we had entered into the following swaps:

Subsequent to September 30, 2010, through October 29, 2010, Forest entered into additional gas swaps. See "Commodity Swaptions" below for further information on these swaps.

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 September 30, 2010, we had entered into the following collars:

In connection with several gas swaps entered into during the nine months ended September 30, 2010, we granted option instruments (several commodity swaptions and one call option) to the gas swap counterparties in exchange for us receiving premium hedged prices on the gas swaps. As of October 29, 2010, none of the options have been exercised by the counterparties. The table below sets forth the outstanding options as of September 30, 2010:

Subsequent to September 30, 2010, through October 29, 2010, we entered into two additional gas swaps covering 25 Bbtu per day for Calendar 2011 for a weighted average hedged price of $5.03 per MMBtu. In connection with these swaps, the counterparties were granted the following oil swaptions:

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 September 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 September 30, 2010 was a net asset of approximately $70.5 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 September 30, 2010, we had entered into the following interest rate swaps:

The estimated fair value of all our interest rate derivative instruments was a net asset of approximately $26.5 million as of September 30, 2010.

The table below sets forth the changes that occurred in the fair values of our open derivative contracts during the nine months ended September 30, 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 September 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 September 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 September 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 September 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, and under Part II, Item 1A, "Risk Factors," in our Form 10-Q for the quarter ended June 30, 2010, there have been no material changes to the risks described in Part I, Item 1A, of the Annual Report.

In August 2007, we closed on the sale of our oil and gas assets in Alaska (the "Alaska Assets") to Pacific Energy Resources, Ltd ("PERL"). In March 2009, PERL filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. PERL requested, and the bankruptcy court has approved, abandonment of PERL's interests in certain of the Alaska Assets. The remaining working interest owners in the Alaska Assets previously made the assertion that, in its role as assignor of the Alaska Assets, Forest should be held liable for any contractual obligations of PERL with respect to the Alaska Assets, including obligations related to operating costs and for costs associated with the final plugging and decommissioning of wells and production facilities. More recently, PERL has asserted during its bankruptcy case that the Alaska Assets were worth less than what PERL paid for them in August 2007, and that Forest may face liability under creditors' rights laws or other laws in connection with the transaction. Forest disagrees with both the working interest owners' assertion and PERL's assertion and, to the extent necessary, will vigorously oppose any efforts to hold Forest liable for PERL's unsatisfied obligations or for the sale of the Alaska Assets to PERL. We cannot predict, however, whether we would be successful in avoiding all such liabilities.

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

The table below sets forth information regarding repurchases of our common stock during the third quarter 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.

		Oil and Gas Exploration and Production

		Three Months Ended September 30, 2010									Nine Months Ended September 30, 2010
		United States		Canada		International			Total Company		United States		Canada		International			Total Company
		(In Thousands)
Oil and gas sales		$	174,991		35,190		—			210,181		529,012		110,852		—			639,864
Costs and expenses:
	Lease operating expenses		23,602		6,575		—			30,177		69,549		18,152		—			87,701
	Production and property taxes		12,751		625		—			13,376		35,419		1,872		—			37,291
	Transportation and processing costs		3,302		2,908		—			6,210		9,228		7,861		—			17,089
	Depletion		47,060		15,708		—			62,768		127,490		45,040		—			172,530
	Accretion of asset retirement obligations		1,416		251		26			1,693		4,592		774		75			5,441

Segment earnings (loss)		$	86,860		9,123		(26	)		95,957		282,734		37,153		(75	)		319,812

Capital expenditures⁽¹⁾		$	146,517		18,237		1,230			165,984		477,282		178,118		3,335			658,735

Goodwill⁽²⁾		$	239,420		16,839		—			256,259		239,420		16,839		—			256,259

Long-lived assets⁽²⁾⁽³⁾		$	1,938,764		586,238		90,293			2,615,295		1,938,764		586,238		90,293			2,615,295

Total assets⁽²⁾		$	3,027,843		656,653		90,934			3,775,430		3,027,843		656,653		90,934			3,775,430

	Three Months Ended September 30, 2010

	(In Thousands)
Segment earnings	$	95,957		319,812
Interest and other income		206		483
General and administrative expense		(18,007	)	(54,541	)
Depreciation and amortization expense		(1,969	)	(6,965	)
Interest expense		(37,088	)	(112,240	)
Realized and unrealized gains on derivative instruments, net		59,156		177,398
Other, net		8,089		5,282

Earnings before income taxes	$	106,344		329,229

		Oil and Gas Exploration and Production

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

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

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

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

Long-lived assets⁽²⁾⁽³⁾		$	2,441,725		533,463		82,773			3,057,961		2,441,725			533,463			82,773			3,057,961

Total assets⁽²⁾		$	3,287,971		585,781		85,683			3,959,435		3,287,971			585,781			85,683			3,959,435

	Three Months Ended September 30, 2009

	(In Thousands)
Segment earnings (loss)	$	61,890		(1,422,397	)
Interest and other income		(42	)	602
General and administrative expense		(17,316	)	(49,050	)
Depreciation and amortization expense		(3,158	)	(8,614	)
Interest expense		(42,653	)	(122,373	)
Realized and unrealized gains on derivative instruments, net		5,665		112,212
Other, net		4,074		1,098

Earnings (loss) before income taxes	$	8,460		(1,488,522	)

			September 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		$	242,115		—			9,484			—			251,599		456,978		379			9,864			—			467,221
	Accounts receivable			36,083		43,699			23,293			(366	)		102,709		79,857		24,406			22,671			(580	)		126,354
	Deferred income taxes			—		—			—			—			—		6,589		519			—			—			7,108
	Other current assets			161,235		771			21,081			—			183,087		115,663		797			12,849			—			129,309

		Total current assets		439,433		44,470			53,858			(366	)		537,395		659,087		26,101			45,384			(580	)		729,992
Property and equipment, at cost				7,331,703		1,176,716			1,860,921			—			10,369,340		7,093,082		1,074,610			1,657,986			—			9,825,678
	Less accumulated depreciation, depletion, and amortization			5,584,022		1,030,670			1,139,353			—			7,754,045		5,502,530		994,005			1,069,936			—			7,566,471

		Net property and equipment		1,747,681		146,046			721,568			—			2,615,295		1,590,552		80,605			588,050			—			2,259,207
Investment in subsidiaries				370,299		—			—			(370,299	)		—		308,424		—			—			(308,424	)		—
Note receivable from subsidiary				224,306		—			—			(224,306	)		—		135,529		—			—			(135,529	)		—
Goodwill				216,460		22,960			16,839			—			256,259		216,460		22,960			16,488			—			255,908
Due from (to) parent and subsidiaries				233,178		(51,171	)		(182,007	)		—			—		215,679		(60,884	)		(154,795	)		—			—
Deferred income taxes				333,264		—			—			(31,324	)		301,940		395,519		—			—			(2,458	)		393,061
Other assets				62,304		6			2,231			—			64,541		44,087		6			2,429			—			46,522

			$	3,626,925		162,311			612,489			(626,295	)		3,775,430		3,565,337		68,788			497,556			(446,991	)		3,684,690

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable and accrued liabilities		$	227,999		3,050			40,961			(366	)		271,644		238,935		6,825			39,122			(580	)		284,302
	Current portion of long-term- debt			—		—			—			—			—		156,678		—			—			—			156,678
	Other current liabilities			88,818		425			8,561			—			97,804		86,633		64			7,343			—			94,040

		Total current liabilities		316,817		3,475			49,522			(366	)		369,448		482,246		6,889			46,465			(580	)		535,020
Long-term debt				1,868,453		—			—			—			1,868,453		1,865,836		—			—			—			1,865,836
Note payable to parent				—		—			224,306			(224,306	)		—		—		—			135,529			(135,529	)		—
Other liabilities				122,526		2,189			39,356			—			164,071		121,869		769			35,158			—			157,796
Deferred income taxes				—		51,678			33,975			(31,324	)		54,329		16,232		4,446			28,664			(2,458	)		46,884

		Total liabilities		2,307,796		57,342			347,159			(255,996	)		2,456,301		2,486,183		12,104			245,816			(138,567	)		2,605,536
Shareholders' equity				1,319,129		104,969			265,330			(370,299	)		1,319,129		1,079,154		56,684			251,740			(308,424	)		1,079,154

			$	3,626,925		162,311			612,489			(626,295	)		3,775,430		3,565,337		68,788			497,556			(446,991	)		3,684,690

		Three Months Ended September 30,

		2010								2009
		Gas		Oil		NGLs		Total		Gas		Oil		NGLs		Total
		(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(MMcf)		(MBbls)		(MBbls)		(MMcfe)
Production volumes:
	United States		25,687		597		971		35,095		27,337		810		682		36,289
	Canada		5,493		217		29		6,969		6,246		149		54		7,464

Totals			31,180		814		1,000		42,064		33,583		959		736		43,753

Revenues (in thousands):
	United States	$	101,268		44,071		29,652		174,991		80,810		52,768		17,661		151,239
	Canada		19,396		14,156		1,638		35,190		15,912		8,531		1,502		25,945

Totals		$	120,664		58,227		31,290		210,181		96,722		61,299		19,163		177,184

Average sales price per unit:
	United States	$	3.94		73.82		30.54		4.99		2.96		65.15		25.90		4.17
	Canada		3.53		65.24		56.48		5.05		2.55		57.26		27.81		3.48

Totals		$	3.87		71.53		31.29		5.00		2.88		63.92		26.04		4.05

Commodity Swaps

	Natural Gas (NYMEX HH)						Oil (NYMEX WTI)							NGLs (OPIS Refined Products)
Remaining Swap Term	Bbtu per Day		Weighted Average Hedged Price per MMBtu		Fair Value (In Thousands)		Barrels per Day		Weighted Average Hedged Price per Bbl		Fair Value (In Thousands)			Barrels per Day		Weighted Average Hedged Price per Bbl		Fair Value (In Thousands)
Oct 2010 - Dec 2010		210	$	6.20	$	43,425		3,000	$	76.06	$	(1,414	)		—	$	—	$	—
Calendar 2011		90		5.86		46,044		—		—		—			3,000		36.75		(1,929	)

Oil Collars (NYMEX WTI)

Remaining Collar Term	Barrels Per Day		Weighted Average Hedged Floor and Ceiling Price per Bbl			Fair Value (In Thousands)
October 2010 - December 2010		2,000	$	60.00/98.50		$	(19	)
Calendar 2011		3,000		75.00/91.87	⁽¹⁾		(1,117	)

	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		140,655			37,803			178,458
Net contract gains realized		(64,816	)		(9,743	)		(74,559	)

As of September 30, 2010	$	70,450			26,480			96,930

	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

July 2010	4,716	$	28.57	—	—
August 2010	8,638		27.73	—	—
September 2010	3,500		29.29	—	—

Third Quarter Total	16,854	$	28.29	—	—


	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*		Form of 2010 Severance Agreement for Senior Vice President.
	10.2*		Form of 2010 Severance Agreement for Vice President.
	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)
November 3, 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)

				Three Months Ended September 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			$	114,416			60,044			35,721			—			210,181			121,119			29,664			26,401			—			177,184
	Interest and other				1,197			10			3			(1,004	)		206			3,130			—			(117	)		(3,055	)		(42	)
	Equity earnings (losses) in subsidiaries				40,968			—			—			(40,968	)		—			35,072			—			—			(35,072	)		—

			Total revenues		156,581			60,054			35,724			(41,972	)		210,387			159,321			29,664			26,284			(38,127	)		177,142
Costs, expenses, and other:
	Lease operating expenses				21,271			2,222			6,684			—			30,177			23,488			4,654			6,796			—			34,938
	Other direct operating costs				12,037			4,405			3,144			—			19,586			12,423			1,395			2,407			—			16,225
	General and administrative				15,032			604			2,371			—			18,007			14,838			586			1,892			—			17,316
	Depreciation, depletion, and amortization				32,692			15,760			16,285			—			64,737			42,165			8,933			14,177			—			65,275
	Interest expense				34,449			230			3,413			(1,004	)		37,088			39,059			2,261			4,388			(3,055	)		42,653
	Realized and unrealized (gains) losses on derivative instruments, net				(47,022	)		(12,022	)		(112	)		—			(59,156	)		(7,754	)		2,076			13			—			(5,665	)
	Other, net				1,750			(580	)		(7,566	)		—			(6,396	)		4,556			181			(6,797	)		—			(2,060	)

		Total costs, expenses, and other			70,209			10,619			24,219			(1,004	)		104,043			128,775			20,086			22,876			(3,055	)		168,682

Earnings (loss) before income taxes					86,372			49,435			11,505			(40,968	)		106,344			30,546			9,578			3,408			(35,072	)		8,460
		Income tax			17,461			18,679			1,293			—			37,433			(141,765	)		(19,733	)		(2,353	)		—			(163,851	)

Net earnings (loss)				$	68,911			30,756			10,212			(40,968	)		68,911			172,311			29,311			5,761			(35,072	)		172,311

				Nine Months Ended September 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			$	373,620			153,539			112,705			—			639,864			376,896			93,341			83,236			—			553,473
	Interest and other				3,964			19			12			(3,512	)		483			9,948			91			(152	)		(9,285	)		602
	Equity earnings (losses) in subsidiaries				100,221			—			—			(100,221	)		—			(259,225	)		—			—			259,225			—

			Total revenues		477,805			153,558			112,717			(103,733	)		640,347			127,619			93,432			83,084			249,940			554,075
Costs, expenses, and other:
	Lease operating expenses				61,388			7,848			18,465			—			87,701			77,178			15,392			21,635			—			114,205
	Other direct operating costs				35,155			10,634			8,591			—			54,380			38,338			4,869			7,070			—			50,277
	General and administrative				45,092			1,767			7,682			—			54,541			41,311			1,913			5,826			—			49,050
	Depreciation, depletion, and amortization				96,182			36,665			46,648			—			179,495			159,928			37,404			40,632			—			237,964
	Ceiling test write-down of oil and gas properties				—			—			—			—			—			1,155,777			218,567			201,499			—			1,575,843
	Interest expense				107,083			1,308			7,361			(3,512	)		112,240			110,338			7,082			14,238			(9,285	)		122,373
	Realized and unrealized gains on derivative instruments, net				(145,083	)		(31,963	)		(352	)		—			(177,398	)		(94,946	)		(17,003	)		(263	)		—			(112,212	)
	Other, net				623			(548	)		84			—			159			10,498			322			(5,723	)		—			5,097

		Total costs, expenses, and other			200,440			25,711			88,479			(3,512	)		311,118			1,498,422			268,546			284,914			(9,285	)		2,042,597

Earnings (loss) before income taxes					277,365			127,847			24,238			(100,221	)		329,229			(1,370,803	)		(175,114	)		(201,830	)		259,225			(1,488,522	)
		Income tax			66,038			47,597			4,267			—			117,902			(402,482	)		(63,339	)		(54,380	)		—			(520,201	)

Net earnings (loss)				$	211,327			80,250			19,971			(100,221	)		211,327			(968,321	)		(111,775	)		(147,450	)		259,225			(968,321	)

		Nine Months Ended September 30,

		2010								2009
		Gas		Oil		NGLs		Total		Gas		Oil		NGLs		Total
		(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(MMcf)		(MBbls)		(MBbls)		(MMcfe)
Production volumes:
	United States		75,791		1,734		2,503		101,213		89,533		2,626		2,274		118,933
	Canada		16,019		648		108		20,555		17,746		480		175		21,676

Totals			91,810		2,382		2,611		121,768		107,279		3,106		2,449		140,609

Revenues (in thousands):
	United States	$	317,114		128,746		83,152		529,012		283,748		136,825		51,214		471,787
	Canada		61,941		43,348		5,563		110,852		53,988		22,776		4,922		81,686

Totals		$	379,055		172,094		88,715		639,864		337,736		159,601		56,136		553,473

Average sales price per unit:
	United States	$	4.18		74.25		33.22		5.23		3.17		52.10		22.52		3.97
	Canada		3.87		66.90		51.51		5.39		3.04		47.45		28.13		3.77

Totals		$	4.13		72.25		33.98		5.25		3.15		51.38		22.92		3.94