Edgar Filing: FOREST OIL CORP

FST-09.30.2012-10Q



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

__________________________________________________

FORM 10-Q

(Mark One)



T	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012



¨	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	25-0484900
(State or other jurisdiction of incorporation or organization)	(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. T Yes ¨ 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). T Yes ¨ 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 T	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company ¨

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

As of October 24, 2012 there were 118,356,478 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, 2012



Part I—FINANCIAL INFORMATION	1
Item 1—Financial Statements	1
Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	1
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011	2
Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011	3
Condensed Consolidated Statement of Equity for the Nine Months Ended September 30, 2012	4
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	5
Notes to Condensed Consolidated Financial Statements	6
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3—Quantitative and Qualitative Disclosures About Market Risk	39
Item 4—Controls and Procedures	43
Part II—OTHER INFORMATION	44
Item 1—Legal Proceedings	44
Item 1A—Risk Factors	44
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 6—Exhibits	46
Signatures	47

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands, Except Share Amounts)



	September 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	39,169		$	3,012
Accounts receivable	77,210			79,089
Derivative instruments	43,853			89,621
Other current assets	16,278			38,950
Total current assets	176,510			210,672
Property and equipment:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $7,892,873 and $6,901,997	1,774,587			1,923,145
Unproved	442,275			675,995
Net oil and natural gas properties	2,216,862			2,599,140
Other property and equipment, net of accumulated depreciation and amortization of $46,040 and $47,989	16,327			51,976
Assets held for sale	27,373			—
Net property and equipment	2,260,562			2,651,116
Deferred income taxes	9,851			231,116
Goodwill	239,420			239,420
Derivative instruments	5,273			10,422
Other assets	90,762			38,405
	$	2,782,378		$	3,381,151
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	189,753		$	247,880
Accrued interest	29,663			23,259
Derivative instruments	7,759			28,944
Deferred income taxes	9,851			20,172
Current portion of long-term debt	296,002			—
Other current liabilities	20,743			20,582
Total current liabilities	553,771			340,837
Long-term debt	1,796,369			1,693,044
Asset retirement obligations	79,133			77,898
Derivative instruments	16,640			—
Other liabilities	93,688			76,259
Total liabilities	2,539,601			2,188,038
Shareholders’ equity:
Preferred stock, none issued and outstanding	—			—
Common stock, 118,225,731 and 114,525,673 shares issued and outstanding	11,823			11,454
Capital surplus	2,538,129			2,486,994
Accumulated deficit	(2,289,461		)	(1,287,063		)
Accumulated other comprehensive loss	(17,714		)	(18,272		)
Total shareholders’ equity	242,777			1,193,113
	$	2,782,378		$	3,381,151

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						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenues:
Oil, natural gas, and natural gas liquids sales	$	156,014		$	174,012		$	450,609		$	526,915
Interest and other	54			109			123			939
Total revenues	156,068			174,121			450,732			527,854
Costs, expenses, and other:
Lease operating expenses	27,426			23,480			82,167			70,593
Production and property taxes	8,842			7,926			26,935			32,187
Transportation and processing costs	3,580			3,197			11,167			10,263
General and administrative	13,416			19,942			45,221			49,122
Depreciation, depletion, and amortization	73,845			54,323			213,802			155,227
Ceiling test write-down of oil and natural gas properties	329,957			—			713,750			—
Impairment of properties	79,529			—			79,529			—
Interest expense	36,223			37,225			103,932			113,081
Realized and unrealized losses (gains) on derivative instruments, net	22,795			(65,961		)	(40,744		)	(70,632		)
Other, net	11,727			(177		)	42,102			12,280
Total costs, expenses, and other	607,340			79,955			1,277,861			372,121
Earnings (loss) from continuing operations before income taxes	(451,272		)	94,166			(827,129		)	155,733
Income tax	7,280			34,556			175,269			76,940
Net earnings (loss) from continuing operations	(458,552		)	59,610			(1,002,398		)	78,793
Net earnings from discontinued operations	—			28,108			—			44,569
Net earnings (loss)	(458,552		)	87,718			(1,002,398		)	123,362
Less: net earnings attributable to noncontrolling interest	—			4,923			—			4,987
Net earnings (loss) attributable to Forest Oil Corporation common shareholders	$	(458,552	)	$	82,795		$	(1,002,398	)	$	118,375

Basic earnings (loss) per common share attributable to Forest Oil Corporation common shareholders:
Earnings (loss) from continuing operations	$	(3.97	)	$	.52		$	(8.73	)	$	.69
Earnings from discontinued operations	—			.20			—			.35
Basic earnings (loss) per common share	$	(3.97	)	$	.72		$	(8.73	)	$	1.04

Diluted earnings (loss) per common share attributable to Forest Oil Corporation common shareholders:
Earnings (loss) from continuing operations	$	(3.97	)	$	.52		$	(8.73	)	$	.69
Earnings from discontinued operations	—			.20			—			.34
Diluted earnings (loss) per common share	$	(3.97	)	$	.72		$	(8.73	)	$	1.03

Amounts attributable to Forest Oil Corporation common shareholders:
Net earnings (loss) from continuing operations	$	(458,552	)	$	59,610		$	(1,002,398	)	$	78,793
Net earnings from discontinued operations	—			23,185			—			39,582
Net earnings (loss)	$	(458,552	)	$	82,795		$	(1,002,398	)	$	118,375

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In Thousands)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net earnings (loss)	$	(458,552	)	$	87,718		$	(1,002,398	)	$	123,362
Other comprehensive income (loss):
Foreign currency translation losses	—			(38,234		)	—			(27,763		)
Unfunded postretirement benefits, net of tax	185			93			558			311
Total other comprehensive income (loss)	185			(38,141		)	558			(27,452		)
Total comprehensive income (loss)	(458,367		)	49,577			(1,001,840		)	95,910
Less: total comprehensive loss attributable to noncontrolling interest	—			(1,824		)	—			(1,330		)
Total comprehensive income (loss) attributable to Forest Oil Corporation common shareholders	$	(458,367	)	$	51,401		$	(1,001,840	)	$	97,240

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

(In Thousands)



	Common Stock					Capital Surplus			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
	Shares		Amount			Capital Surplus			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balances at December 31, 2011	114,526		$	11,454		$	2,486,994		$	(1,287,063	)	$	(18,272	)	$	1,193,113
Common stock issued for acquisition of unproved oil and natural gas properties	2,657		266			36,165			—			—			36,431
Employee stock purchase plan	128		13			907			—			—			920
Restricted stock issued, net of forfeitures	1,198		120			(120		)	—			—			—
Amortization of stock-based compensation	—		—			18,181			—			—			18,181
Other, net	(283	)	(30		)	(3,998		)	—			—			(4,028		)
Net loss	—		—			—			(1,002,398		)	—			(1,002,398		)
Other comprehensive income	—		—			—			—			558			558
Balances at September 30, 2012	118,226		$	11,823		$	2,538,129		$	(2,289,461	)	$	(17,714	)	$	242,777

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,
	2012			2011
Operating activities:
Net earnings (loss)	$	(1,002,398	)	$	123,362
Less: net earnings from discontinued operations	—			44,569
Net earnings (loss) from continuing operations	(1,002,398		)	78,793
Adjustments to reconcile net earnings (loss) from continuing operations to net cash provided by operating activities of continuing operations:
Depreciation, depletion, and amortization	213,802			155,227
Deferred income tax	208,990			46,724
Unrealized losses (gains) on derivative instruments, net	46,372			(40,538		)
Ceiling test write-down of oil and natural gas properties	713,750			—
Impairment of properties	79,529			—
Stock-based compensation expense	12,227			17,809
Accretion of asset retirement obligations	4,914			4,496
Other, net	6,438			6,074
Changes in operating assets and liabilities:
Accounts receivable	9,070			29,686
Other current assets	4,426			8,262
Accounts payable and accrued liabilities	2,182			(5,096		)
Accrued interest and other	(13,477		)	3,977
Net cash provided by operating activities of continuing operations	285,825			305,414
Investing activities:
Capital expenditures for property and equipment:
Exploration, development, and leasehold acquisition costs	(598,882		)	(656,894		)
Other fixed assets	(6,011		)	(4,370		)
Proceeds from sales of assets	8,902			120,956
Net cash used by investing activities of continuing operations	(595,991		)	(540,308		)
Financing activities:
Proceeds from bank borrowings	651,000			12,000
Repayments of bank borrowings	(756,000		)	(12,000		)
Issuance of senior notes, net of issuance costs	491,250			—
Payment of debt issue costs	(872		)	(8,198		)
Change in bank overdrafts	(37,716		)	(20,660		)
Other, net	(1,339		)	(4,109		)
Net cash provided (used) by financing activities of continuing operations	346,323			(32,967		)
Cash flows of discontinued operations:
Operating cash flows	—			101,292
Investing cash flows	—			(255,470		)
Financing cash flows	—			478,324
Net cash provided by discontinued operations	—			324,146
Effect of exchange rate changes on cash	—			(3,476		)
Net increase in cash and cash equivalents	36,157			52,809
Net increase in cash and cash equivalents of discontinued operations	—			(289		)
Net increase in cash and cash equivalents of continuing operations	36,157			52,520
Cash and cash equivalents of continuing operations at beginning of period	3,012			217,569
Cash and cash equivalents of continuing operations at end of period	$	39,169		$	270,089
Cash paid by continuing operations during the period for:
Interest (net of capitalized amounts)	$	88,619		$	94,398
Income taxes (net of refunded amounts)	979			31,523
Non-cash investing activities of continuing operations:
Increase (decrease) in accrued capital expenditures	$	(22,878	)	$	38,927
Increase in asset retirement costs	4,786			2,553
Common stock issued for acquisition of unproved oil and natural gas properties	36,431			—

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) ORGANIZATION AND BASIS OF PRESENTATION

Organization

Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGL”) primarily in the United States. 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. Forest holds assets in several exploration and producing areas in the United States and has exploratory and development interests in two other countries. On June 1, 2011, Forest completed an initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which held Forest’s ownership interests in its Canadian operations. On September 30, 2011, Forest distributed, or spun-off, its remaining 82% ownership in Lone Pine to Forest’s shareholders, by means of a special stock dividend of Lone Pine common shares. Unless the context indicates otherwise, the terms “Forest,” the “Company,” “we,” “our,” and “us,” as used in this Quarterly Report on Form 10-Q, refer to Forest Oil Corporation and its subsidiaries.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein are unaudited and include the accounts of Forest and its consolidated subsidiaries. As a result of the spin-off, Lone Pine’s results of operations are reported as discontinued operations in Forest’s Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011. See Note 10 for more information regarding the results of operations of Lone Pine. In the opinion of management, all adjustments, which are of a normal recurring nature, have been made that are necessary for a fair presentation of the financial position of Forest at September 30, 2012, and the results of its operations, its comprehensive income, its cash flows, and changes in its shareholders’ equity for the periods presented. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in the prices of oil, natural gas, and natural gas liquids and the impact the prices have on Forest’s revenues and the fair values of its derivative instruments.

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, natural gas, and natural gas liquids 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 and goodwill, valuing deferred tax assets, 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 2012 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, 2011, previously filed with the Securities and Exchange Commission (“SEC”).

(2) 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. The two-class method of computing earnings (loss) per share is required to be used since Forest has participating securities. The two-class method is an earnings allocation formula that determines earnings (loss) per share for each class of common stock and participating 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 and certain non-cash dividends, participating on an equal basis with common stock. Holders of phantom stock units issued to directors under Forest’s stock

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incentive plans also have the right to receive non-forfeitable cash and certain non-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 and common shares have been 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 peer companies. See Note 3 for more information on Forest’s stock-based incentive awards. 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.

Under the treasury stock method, diluted earnings (loss) per share is computed by dividing (a) net earnings (loss), adjusted for the effects of certain contracts that provide the issuer or holder with a choice between settlement methods, by (b) 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 are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and nine months ended September 30, 2012. Unvested restricted stock grants were not included in the calculation of diluted earnings per share for the three and nine months ended September 30, 2011 as their inclusion would have an antidilutive effect. Unvested performance stock units were not included in the calculation of diluted earnings per share for the three and nine months ended September 30, 2011 as no shares would have been earned under the performance stock unit agreements if September 30, 2011 had been the end of the vesting period under these agreements.

The following reconciles net earnings (loss) as reported in the Condensed Consolidated Statements of Operations to net earnings (loss) used for calculating basic and diluted earnings (loss) per share for the periods presented.



	Three Months Ended September 30,
	2012								2011
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(In Thousands)
Net earnings (loss)	$	(458,552	)	$	—	$	(458,552	)	$	59,610		$	28,108		$	87,718
Net earnings attributable to noncontrolling interest	—			—		—			—			(4,923		)	(4,923		)
Net earnings attributable to participating securities	—			—		—			(1,341		)	(522		)	(1,863		)
Net earnings (loss) attributable to common stock for basic earnings per share	$	(458,552	)	$	—	$	(458,552	)	$	58,269		$	22,663		$	80,932
Adjustment for liability classified stock-based compensation awards	—			—		—			—			(603		)	(603		)
Net earnings (loss) for diluted earnings per share	$	(458,552	)	$	—	$	(458,552	)	$	58,269		$	22,060		$	80,329



	Nine Months Ended September 30,
	2012								2011
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(In Thousands)
Net earnings (loss)	$	(1,002,398	)	$	—	$	(1,002,398	)	$	78,793		$	44,569		$	123,362
Net earnings attributable to noncontrolling interest	—			—		—			—			(4,987		)	(4,987		)
Net earnings attributable to participating securities	—			—		—			(1,606		)	(807		)	(2,413		)
Net earnings (loss) attributable to common stock for basic earnings per share	$	(1,002,398	)	$	—	$	(1,002,398	)	$	77,187		$	38,775		$	115,962
Adjustment for liability classified stock-based compensation awards	—			—		—			—			(707		)	(707		)
Net earnings (loss) for diluted earnings per share	$	(1,002,398	)	$	—	$	(1,002,398	)	$	77,187		$	38,068		$	115,255

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The following reconciles basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the periods presented.



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2012	2011	2012	2011
	(In Thousands)
Weighted average common shares outstanding during the period for basic earnings (loss) per share	115,417	111,810	114,784	111,598
Dilutive effects of potential common shares	—	352	—	521
Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings (loss) per share	115,417	112,162	114,784	112,119

(3) STOCK-BASED COMPENSATION

Equity Incentive Plans

Forest maintains the 2001 and 2007 Stock Incentive Plans (the “Plans”) under which qualified and non-qualified stock options, restricted stock, performance units, phantom stock units, and other awards may be granted to employees, consultants, and non-employee directors of Forest and its subsidiaries.

Compensation Costs

The table below sets forth stock-based compensation of continuing operations for the three and nine months ended September 30, 2012 and 2011, and the remaining unamortized amounts and weighted average amortization period as of September 30, 2012.



	Stock Options			Restricted Stock			Performance Units			Phantom Stock Units				Total⁽¹⁾
	(In Thousands)
Three months ended September 30, 2012:
Total stock-based compensation costs	$	—		$	3,500		$	1,273		$	909			$	5,682
Less: stock-based compensation costs capitalized	—			(1,435		)	(455		)	(402		)		(2,292		)
Stock-based compensation costs expensed	$	—		$	2,065		$	818		$	507			$	3,390
Nine months ended September 30, 2012:
Total stock-based compensation costs	$	—		$	12,219		$	5,630		$	796			$	18,645
Less: stock-based compensation costs capitalized	—			(4,630		)	(1,322		)	(532		)		(6,484		)
Stock-based compensation costs expensed	$	—		$	7,589		$	4,308		$	264			$	12,161
Unamortized stock-based compensation costs	$	—		$	19,517		$	5,978		$	4,618		⁽²⁾	$	30,113
Weighted average amortization period remaining	—			1.9 years			1.7 years			1.5 years				1.8 years
Three months ended September 30, 2011:
Total stock-based compensation costs	$	1,095		$	15,434		$	775		$	(1,456	)		$	15,848
Less: stock-based compensation costs capitalized	(437		)	(6,994		)	(253		)	529				(7,155		)
Stock-based compensation costs expensed	$	658		$	8,440		$	522		$	(927	)		$	8,693
Nine months ended September 30, 2011:
Total stock-based compensation costs	$	1,536		$	26,566		$	2,181		$	(1,788	)		$	28,495
Less: stock-based compensation costs capitalized	(663		)	(11,522		)	(683		)	696				(12,172		)
Stock-based compensation costs expensed	$	873		$	15,044		$	1,498		$	(1,092	)		$	16,323

____________________________________________


(1)	The Company also maintains an employee stock purchase plan (which is not included in the table) under which $.1 million and $.3 million of compensation cost was recognized for the three and nine month periods ended September 30, 2012, respectively, and $.1 million and $.4 million of compensation cost was recognized for the three and nine month periods ended September 30, 2011, respectively.


(2)	Based on the closing price of Forest’s common stock on September 30, 2012.

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Stock Options

The following table summarizes stock option activity in the Plans for the nine months ended September 30, 2012.



	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In Thousands)⁽¹⁾		Number of Options Exercisable
Outstanding at January 1, 2012	1,766,587		$	14.55	$	2,731	1,766,587
Granted	—		—
Exercised	—		—		—
Cancelled	(879,843	)	11.08
Outstanding at September 30, 2012	886,744		$	17.99	$	—	886,744

____________________________________________


(1)	The intrinsic value of a stock option is the amount by which the market value of the underlying stock, as of the date outstanding or exercised, exceeds the exercise price of the option.

Restricted Stock, Performance Units, and Phantom Stock Units

The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Plans for the nine months ended September 30, 2012.



	Restricted Stock						Performance Units						Phantom Stock Units
	Number of Shares		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)		Number of Units⁽¹⁾		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)		Number of Units⁽²⁾		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)
Unvested at January 1, 2012	2,474,112		$	24.00			655,120		$	19.50			1,238,817		$	14.32
Awarded	1,524,594		10.16				511,500		14.70				—		—
Vested	(891,207	)	19.46		$	7,236	(323,760	)	18.18		$	—	(274,897	)	12.23		$	2,313
Forfeited	(326,430	)	19.20				(181,680	)	17.55				(73,249	)	15.71
Unvested at September 30, 2012	2,781,069		$	18.43			661,180		$	16.97			890,671		$	14.85

____________________________________________

(1)

Forest granted 511,500 performance units on March 12, 2012, with a grant date fair value of $14.70 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 February 28, 2015.


(2)	All of the unvested phantom stock units at September 30, 2012 must be settled in cash. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements. Of the 274,897 phantom stock units that vested during the nine months ended September 30, 2012, 268,817 were settled in cash, while the remaining 6,080 were settled in shares.

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(4) DEBT

The components of debt are as follows:



	September 30, 2012									December 31, 2011
	Principal			Unamortized Premium (Discount)			Total			Principal		Unamortized Premium (Discount)			Total
	(In Thousands)
Credit Facility	$	—		$	—		$	—		$	105,000	$	—		$	105,000
7% Senior Subordinated Notes due 2013	12			—			12			12		—			12
8½% Senior Notes due 2014⁽¹⁾	600,000			(8,020		)	591,980			600,000		(12,389		)	587,611
7¼% Senior Notes due 2019	1,000,000			379			1,000,379			1,000,000		421			1,000,421
7½% Senior Notes due 2020	500,000			—			500,000			—		—			—
Total debt	$	2,100,012		$	(7,641	)	$	2,092,371		$	1,705,012	$	(11,968	)	$	1,693,044
Less: current portion of long-term debt⁽¹⁾	(300,012		)	4,010			(296,002		)	—		—			—
Long-term debt	$	1,800,000		$	(3,631	)	$	1,796,369		$	1,705,012	$	(11,968	)	$	1,693,044

____________________________________________


(1)	In September 2012, the Company irrevocably called $300.0 million (50% of the aggregate principal amount) of the 8½% senior notes due 2014 and redeemed those called notes in October 2012 at 110.24% of par, recognizing a loss of $36.3 million upon redemption.

Bank Credit Facility

As of September 30, 2012, the Company had a $1.5 billion credit facility (the “Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A. (the “Administrative Agent”), which matures in June 2016. The size of the Credit Facility may be increased by $300.0 million, to a total of $1.8 billion, upon agreement between the applicable lenders and Forest.

Forest’s availability under the Credit Facility is governed by a borrowing base. As of September 30, 2012, the borrowing base under the Credit Facility was $1.20 billion. The determination of the 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 Facility could increase or decrease based on such redetermination. In addition to the scheduled 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 borrowing base redetermined. The borrowing base is also subject to automatic adjustments if certain events occur, such as if Forest or any of its Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that Forest or any of its Restricted Subsidiaries may issue to refinance then-existing senior notes. This was the case in September 2012, when the borrowing base was reduced by $50.0 million from $1.25 billion to $1.20 billion. The borrowing base is also subject to automatic adjustment if Forest or any of its Restricted Subsidiaries sell oil and natural gas properties included in the borrowing base, as applicable, having a fair market value in excess of 10% of the borrowing base then in effect. In this case, the borrowing base would be reduced by an amount either (i) equal to the percentage of the borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by Forest and the required lenders. Forest expects the sale of its south Louisiana properties for $220.0 million, discussed in Note 5 below, will result in an approximate $80.0 million reduction to its borrowing base when the transaction closes.

Effective October 5, 2012, the lenders completed the most recent scheduled semi-annual redetermination of the borrowing base, reducing the borrowing base to $1.15 billion. The next scheduled semi-annual redetermination of the borrowing base will occur on or about May 1, 2013. A lowering of the borrowing base could require Forest to repay indebtedness in excess of the borrowing base in order to cover the deficiency. The Credit Facility is collateralized by Forest’s assets, and Forest is required to mortgage and grant a security interest in 75% of the present value of the estimated proved oil and gas properties and related assets of Forest and its U.S. subsidiaries.

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ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.5 to 1.0 at any time.

At September 30, 2012, there were no outstanding borrowings under the Credit Facility.

7½% Senior Notes Due 2020

On September 17, 2012, Forest issued $500.0 million in principal amount of 7½% senior notes due 2020 (the “7½% Notes”) at par for net proceeds of $491.3 million, after deducting initial purchaser discounts. Net proceeds from the 7½% Notes were used to redeem $300.0 million in principal amount of the 8½% senior notes due 2014 at 110.24% of par in October 2012 (after the required notice of redemption period elapsed), with the balance of the net proceeds used to reduce outstanding borrowings under the Credit Facility. Prior to redeeming a portion of the 8½% senior notes due 2014, the net proceeds were used to temporarily reduce outstanding borrowings under the Credit Facility. Interest on the 7½% Notes is payable semiannually on March 15 and September 15.

The 7½% Notes are redeemable, at Forest’s option, at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued but unpaid interest, if redeemed during the 12-month period beginning on or after September 15 of the years indicated below:



2016	103.75	%
2017	101.88	%
2018 and thereafter	100.00	%

Forest may also redeem the 7½% Notes, in whole or in part, at any time prior to September 15, 2016, at a price equal to the principal amount plus a make-whole premium, calculated using the applicable Treasury yield plus 0.5%, plus accrued but unpaid interest. In addition, prior to September 15, 2015, Forest may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 7½% Notes with the net proceeds of certain equity offerings at 107.5% of the principal amount of the 7½% Notes, plus any accrued but unpaid interest, if at least 65% of the aggregate principal amount of the 7½% Notes remains outstanding after such redemption and the redemption occurs within 120 days of the date of the closing of such equity offering.

(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. Concurrent with the spin-off of Lone Pine on September 30, 2011, the Company no longer has any operations in 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, 2012 and 2011, Forest capitalized $9.3 million and $15.8 million, respectively, of general and administrative costs (including stock-based compensation) related to its continuing operations. During the nine months ended September 30, 2012 and 2011, Forest capitalized $29.6 million and $37.9 million, respectively, of general and administrative costs (including stock-based compensation) related to its continuing operations. 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, 2012 and 2011, Forest capitalized $1.7 million and $3.0 million, respectively, of interest costs attributed to the unproved properties of its continuing operations. During the nine months ended September 30, 2012 and 2011, Forest capitalized $5.8 million and $7.5 million, respectively, of interest costs attributed to the unproved properties of its continuing operations.

Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed at least annually 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 individually assess the amount of impairment of properties for which costs are not individually significant, such

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properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.

During the quarter ended September 30, 2012, Forest recorded a $66.9 million impairment of its unproved properties in South Africa. After several unsuccessful attempts to sell the South African properties, Forest determined that it would likely not recover the carrying amount of its investment in these properties. Because Forest has no proved reserves in South Africa, the impairment was reported as a period expense rather than being added to the costs to be amortized and is included in the Condensed Consolidated Statements of Operations within the “Impairment of properties” line item.

Gain or loss is not recognized on the sale of oil and natural gas properties unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and natural 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.

The Company performs a ceiling test each quarter on a country-by-country basis under the full cost method of accounting. The 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, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs.

As a result of this limitation on capitalized costs, the accompanying financial statements include provisions for ceiling test write-downs of oil and natural gas property costs for the three and nine months ended September 30, 2012 of $330.0 million and $713.8 million, respectively. During the three months ended September 30, 2012, Forest recorded a $330.0 million ceiling test write-down of its United States cost center and during the three months ended June 30, 2012, Forest recorded a $349.0 million ceiling test write-down of its United States cost center. Both of these ceiling test write-downs resulted primarily from a decrease in natural gas and natural gas liquids prices. During the three months ended March 31, 2012, Forest recorded a $34.8 million ceiling test write-down of its Italian cost center due to an Italian regional regulatory body’s denial of Forest’s environmental impact assessment (“EIA”). Approval of the EIA is necessary in order for Forest to commence production in Italy. Forest is currently appealing the region’s denial; however, in the meantime, Forest determined that it can no longer conclude with reasonable certainty that its Italian natural gas reserves are producible and, therefore, can no longer be classified as proved reserves. Additional write-downs of the United States cost center may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenue from estimated production of proved oil and natural gas reserves decline compared to prices used as of September 30, 2012, unproved property values decrease, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center.

Divestitures

In August 2012, the Company entered into an agreement to sell the majority of its East Texas natural gas gathering assets for $34.0 million in cash. Forest can also earn up to $9.0 million of additional performance payments contingent on future activity. The transaction is expected to close on October 31, 2012 and is subject to customary closing conditions and purchase price adjustments, including effective date and title defect adjustments. In conjunction with the sale, Forest entered into a ten-year natural gas gathering agreement with the buyer under which Forest will pay market-based gathering rates and commit the production from its existing and future operated wells located within five miles of the current configuration of the gathering system. As of September 30, 2012, these assets are presented in the Condensed Consolidated Balance Sheet as assets held for sale and were written down to their estimated fair value less cost to sell of $27.4 million, with a $12.7 million impairment charge included in the Condensed Consolidated Statements of Operations within the “Impairment of properties” line item. Forest determined that the estimated cash proceeds from the sale of these assets approximates the fair value of the assets since the sales agreement was negotiated at arm’s length with an unrelated third-party. This non-recurring fair value measurement is categorized within the Level 3 fair value hierarchy (see Note 7 for more information on the fair value hierarchy). Since there will be a continuation of cash flows between Forest and the disposed component by way of the natural

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gas gathering agreement, these assets do not qualify for discontinued operations reporting. Forest intends to use the proceeds from this divestiture to repay outstanding borrowings under the Credit Facility.

In October 2012, Forest entered into an agreement to sell all of its oil and natural gas properties located in south Louisiana for $220.0 million in cash. The transaction is expected to close in November 2012, subject to customary closing conditions and purchase price adjustments. Forest intends to use the proceeds from this divestiture to repay outstanding borrowings under the Credit Facility.

During the three and nine months ended September 30, 2012, Forest also sold miscellaneous oil and natural gas properties for proceeds of $7.8 million and $8.8 million, respectively.

Acquisitions

In February 2012, the Company issued 2.7 million shares of common stock, valued at $36.4 million, pursuant to a lease purchase agreement whereby Forest acquired leases on unproved oil and natural gas properties in the Wolfbone oil play in the Permian Basin in Texas.

(6) INCOME TAXES

A reconciliation of reported income tax attributable to continuing operations to the amount of income tax that would result from applying the United States federal statutory income tax rate to pretax earnings (loss) from continuing operations is as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In Thousands)
Federal income tax at 35% of earnings (loss) from continuing operations before income taxes	$	(157,945	)	$	32,958		$	(289,495	)	$	54,507
State income taxes, net of federal income tax benefits	(5,442		)	1,107			(9,983		)	1,830
Canadian dividend tax, net of U.S. tax benefit	—			—			—			18,460
Effect of federal, state, and foreign tax on permanent items	342			1,397			997			2,243
Change in valuation allowance	170,065			—			472,569			—
Other	260			(906		)	1,181			(100		)
Total income tax	$	7,280		$	34,556		$	175,269		$	76,940

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(7) FAIR VALUE MEASUREMENTS

The Company’s assets and liabilities measured at fair value on a recurring basis at September 30, 2012 and December 31, 2011 are set forth in the table below.



	September 30, 2012		December 31, 2011
	Using Significant Other Observable Inputs (Level 2)⁽¹⁾
	(In Thousands)
Assets:
Derivative instruments⁽²⁾:
Commodity	$	33,282	$	79,487
Interest rate	15,844		20,556
Total assets	$	49,126	$	100,043
Liabilities:
Derivative instruments⁽²⁾:
Commodity	$	24,399	$	28,944
Interest rate	—		—
Total liabilities	$	24,399	$	28,944

____________________________________________

(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 relevant observable inputs are not available. There were no transfers between levels of the fair value hierarchy during the three and nine months ended September 30, 2012. The Company’s policy is to recognize transfers between levels of the fair value hierarchy as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

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



	September 30, 2012
					Fair Value Measurements:
	Carrying Amount		Total Fair Value⁽¹⁾		Using Quoted Prices in Active Markets for Identical Assets (Level 1)		Using Significant Other Observable Inputs (Level 2)
	(In Thousands)
Assets:
Derivative instruments	$	49,126	$	49,126	$	—	$	49,126
Liabilities:
Derivative instruments	24,399		24,399		—		24,399
8½% Senior Notes due 2014	591,980		651,000		651,000		—
7¼% Senior Notes due 2019	1,000,379		990,000		990,000		—
7½% Senior Notes due 2020	500,000		497,190		497,190		—

__________________________________________


(1)	The Company used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior 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 for more information on the derivative instruments.

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	December 31, 2011
	Carrying Amount		Fair Value⁽¹⁾
	(In Thousands)
Assets:
Derivative instruments	$	100,043	$	100,043
Liabilities:
Derivative instruments	28,944		28,944
Credit Facility	105,000		105,000
8½% Senior Notes due 2014	587,611		653,250
7¼% Senior Notes due 2019	1,000,421		1,025,000

__________________________________________

(1)

The Company used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on quoted market prices. The carrying amount of the credit facility approximated fair value due to the short original maturities of the borrowings and because the borrowings bear interest at variable market rates. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 8 for more information on the derivative instruments.

(8) DERIVATIVE INSTRUMENTS

Commodity Derivatives

Forest periodically enters into commodity derivative instruments such as swap and collar agreements as an attempt to moderate the effects of wide fluctuations in commodity prices on Forest’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, Forest has elected not to designate its derivatives as hedging instruments for accounting purposes. As such, Forest 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 as of September 30, 2012.



Commodity Swaps
	Natural Gas (NYMEX HH)			Oil (NYMEX WTI)			NGL (OPIS Refined Products)
Remaining 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
October 2012 - December 2012⁽¹⁾	155	$	4.63	4,500	$	97.26	2,000	$	45.22
Calendar 2013	160	3.98		4,000	95.53		—	—

____________________________________________

(1)

50 Bbtu per day of 2012 gas swaps with a weighted average hedged price per MMBtu of $5.30 are layered with a written put of $3.53 and a call spread of $4.00 to $4.50. Together with the put and call spread, Forest will receive the $5.30 swap price on 50 Bbtu per day except as follows: Forest will receive (i) NYMEX HH plus $1.77 when NYMEX HH is below $3.53; (ii) $5.30 plus the value of the call spread when NYMEX HH is between $4.00 and $4.50; and (iii) $5.80 when NYMEX HH is $4.50 or above.

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In connection with several natural gas and oil swaps entered into, Forest granted option instruments (several commodity swaptions and puts) to the swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas and oil swaps. Under the terms of the commodity swaption agreements, the counterparties have the right, but not the obligation, to enter into a specified swap agreement with Forest before the option expires. The table below sets forth key provisions of the outstanding options as of September 30, 2012. (As of October 24, 2012, none of the options in the table have been exercised by the counterparties.)



Commodity Options
		Natural Gas (NYMEX HH)			Oil (NYMEX WTI)
Underlying Term	Option Expiration	Underlying Bbtu Per Day	Underlying Hedged Price per MMBtu		Underlying Barrels Per Day	Underlying Hedged Price per Bbl
Gas Swaptions:
Calendar 2013	December 2012	30	$	4.02	—	$	—
Calendar 2013	December 2012	10	4.01		—	—
Oil Swaptions:
Calendar 2013	December 2012	—	—		2,000	95.00
Calendar 2014	December 2013	—	—		2,000	110.00
Calendar 2014	December 2013	—	—		1,000	109.00
Calendar 2014	December 2013	—	—		2,000	100.00
Calendar 2015	December 2014	—	—		3,000	100.00
Oil Put Options:
Monthly Oct - Dec 2012	Monthly Oct - Dec 2012	—	—		5,000	75.00

Derivative Instruments Entered Into Subsequent to September 30, 2012

Subsequent to September 30, 2012, through October 24, 2012, we entered into the following derivative agreements:



Commodity Swaps
	Natural Gas (NYMEX HH)
Swap Term	Bbtu Per Day	Weighted Average Hedged Price per MMBtu
Calendar 2014⁽¹⁾	40	$	4.50

____________________________________


(1)	In connection with entering into these natural gas swaps with premium hedged prices, Forest granted options to the counterparties to enter into gas swaps with Forest for Calendar 2014 covering 40 Bbtu per day at a weighted average hedged price per MMBtu of $4.50, with such options expiring in December 2013.

Interest Rate Derivatives

Forest periodically enters into interest rate derivative instruments 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, 2012.



Interest Rate Swaps
Remaining Term	Notional Amount (In Thousands)		Weighted Average Floating Rate	Weighted Average Fixed Rate
October 2012 - February 2014	$	500,000	1 month LIBOR + 5.89%	8.50	%

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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 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, 2012		December 31, 2011
	(In Thousands)
Current assets:
Commodity derivatives:
Derivative instruments	$	32,369	$	79,487
Interest rate derivatives:
Derivative instruments	11,484		10,134
Total current assets	$	43,853	$	89,621
Long-term assets:
Commodity derivatives:
Derivative instruments	$	913	$	—
Interest rate derivatives:
Derivative instruments	4,360		10,422
Total long-term assets	$	5,273	$	10,422
Current liabilities:
Commodity derivatives:
Derivative instruments	$	7,759	$	28,944
Long-term liabilities:
Commodity derivatives:
Derivative instruments	$	16,640	$	—

The table below summarizes the amount of derivative instrument gains and losses reported in the Condensed Consolidated Statements of Operations as net realized and unrealized (gains) losses on derivative instruments for the periods indicated. These derivative instruments are not designated as hedging instruments for accounting purposes.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In Thousands)
Commodity derivatives:
Realized gains	$	(26,242	)	$	(8,639	)	$	(78,637	)	$	(21,478	)
Unrealized losses (gains)	50,231			(51,886		)	41,659			(36,113		)
Interest rate derivatives:
Realized gains	(2,758		)	(2,774		)	(8,479		)	(8,616		)
Unrealized losses (gains)	1,564			(2,662		)	4,713			(4,425		)
Realized and unrealized losses (gains) on derivative instruments, net	$	22,795		$	(65,961	)	$	(40,744	)	$	(70,632	)

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 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.

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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. As of September 30, 2012, all but one of Forest’s derivative counterparties are lenders, or affiliates of lenders, under the Credit Facility. The terms of the Credit Facility provide that any security granted by Forest thereunder shall also extend to and be available to those lenders that are counterparties to derivative transactions. None of these counterparties requires collateral beyond that already pledged under the Credit Facility. The remaining counterparty, a purchaser of Forest’s natural gas production, generally owes money to Forest and therefore does not require collateral under the ISDA Master Agreement and Schedule it has executed with Forest.

The ISDA Master Agreements and Schedules contain cross-default provisions whereby a default under the Credit Facility will also cause a default under the derivative agreements. Such events of default include non-payment, breach of warranty, non-performance of the financial covenant, default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility. In addition, bankruptcy and insolvency events with respect to Forest or certain of its U.S. subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility. None of these events of default is 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 majority of Forest’s derivative counterparties are 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, the ISDA Master Agreements and Schedules generally 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 generally apply to all derivative transactions, or all derivative transactions of the same type (e.g., commodity, interest rate, etc.), 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 $28.7 million at September 30, 2012. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net obligations due to it under the derivative agreements. At September 30, 2012, Forest owed a net derivative liability to three counterparties, the fair value of which was $4.0 million. In the absence of netting provisions, at September 30, 2012, Forest would be exposed to a risk of loss of $49.1 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $24.4 million.

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted. As part of a broader financial regulatory reform, the Dodd-Frank Act includes derivatives reform that may impact Forest’s business. Congress delegated many of the details of the Dodd-Frank Act to federal regulatory agencies, which are in the process of writing and implementing new rules. Forest is monitoring the impact, if any, that the Dodd-Frank Act and related rules will have on its existing derivative transactions under its outstanding ISDA Master Agreements and Schedules, as well as its ability to enter into such transactions and agreements in the future.

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(9) 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					Nine Months Ended
	September 30,					September 30,
	2012		2011			2012		2011
	(In Thousands)
Accretion of asset retirement obligations	$	1,719	$	1,539		$	4,914	$	4,496
Legal proceeding liabilities	6,404		—			29,251		6,500
Other, net	3,604		(1,716		)	7,937		1,284
	$	11,727	$	(177	)	$	42,102	$	12,280

Legal Proceeding Liabilities

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled, Forest Oil Corporation, et al. v. El Rucio Land & Cattle Company Inc., et al., which occurred in Harris County, Texas. The third member of the arbitration panel has dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration decision awards the claimant $22.8 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55^th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest is seeking to have this judgment reversed on appeal and believes it has meritorious arguments in support thereof. However, Forest is unable to predict the final outcome in this matter and has accrued a liability, which is classified within “Other liabilities” in the Condensed Consolidated Balance Sheet, of $22.8 million for this matter.

In August 2007, Forest sold all of its Alaska assets to Pacific Energy Resources Ltd. and its related entities (“PERL”). On March 9, 2009, PERL filed for bankruptcy. As part of the plan of liquidation of its bankruptcy, PERL “abandoned” its interests in many of the Alaska assets sold to it by Forest, including the Trading Bay Unit and Trading Bay Field (“Trading Bay”). On December 2, 2010, Union Oil Company of California (“Unocal”) filed a lawsuit styled, Union Oil Company of California v. Forest Oil Corporation. In the lawsuit, the plaintiff complained about PERL’s abandonment of Trading Bay and asserted that PERL has failed to pay approximately $49.0 million in joint interest billings owed on those properties to date from the time PERL owned them. The plaintiff claimed that, as predecessor of PERL, Forest was liable for PERL’s share of all joint interest billings owed on Trading Bay. As of December 31, 2011, Unocal sold its interest in the Trading Bay assets, including its claims against Forest, to Hilcorp Alaska, LLC, and Hilcorp was substituted for Unocal as plaintiff in the lawsuit. In August 2012, Forest and the plaintiff reached a settlement whereby the plaintiff released Forest from all claims, agreed to indemnify Forest with respect to all decommissioning and abandonment liabilities associated with Trading Bay, and dismissed the complaint against Forest in exchange for a $7.0 million payment from Forest.

On March 7, 2011, Pacific Energy Resources Ltd., Pacific Energy Alaska Holdings LLC, and Pacific Energy Alaska Operating LLC filed suit against Forest Oil Corporation and Forest Alaska Holdings LLC in United States Bankruptcy Court in the District of Delaware. In this suit, the plaintiffs claimed that, at the time Forest sold Pacific Energy Resources Ltd. its Alaska assets, those assets were overvalued due to Forest’s alleged nondisclosure, fraud, and negligent misrepresentations and that, as a result, the sales transaction rendered Pacific Energy Resources Ltd. insolvent. The plaintiffs sought to recover over $250.0 million in value from Forest. During the second quarter of 2011, Forest and the plaintiffs in this action reached a settlement whereby the plaintiffs released Forest from all claims and agreed to dismiss the complaint against Forest in exchange for a $6.5 million payment from Forest.

(10) DISCONTINUED OPERATIONS

On June 1, 2011, Forest completed an initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone Pine, which held Forest’s ownership interests in its Canadian operations. In May 2011, as part of a corporate restructuring in anticipation of Lone Pine’s initial public offering, Lone Pine Resources Canada Ltd. (“LPR Canada”), Forest’s former Canadian subsidiary, declared a stock dividend to Forest immediately before Forest’s contribution of LPR Canada to Lone Pine, with such stock dividend resulting in Forest incurring a dividend tax payable to Canadian federal tax

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authorities of $28.9 million, which Forest paid in June 2011. This dividend tax is classified within “Income tax” in the Condensed Consolidated Statement of Operations. The net proceeds from the initial public offering received by Lone Pine, after deducting underwriting discounts and commissions and offering expenses, were approximately $178.0 million. Lone Pine used the net proceeds to pay $29.2 million to Forest as partial consideration for Forest’s contribution to Lone Pine of Forest’s direct and indirect interests in its Canadian operations. Additionally, Lone Pine used the remaining net proceeds and borrowings under Lone Pine’s credit facility to repay Lone Pine’s outstanding indebtedness owed to Forest, consisting of a note payable, intercompany advances, and accrued interest, of $400.5 million. On September 30, 2011, Forest distributed, or spun-off, its remaining 82% ownership in Lone Pine to Forest’s shareholders, by means of a special stock dividend whereby Forest shareholders received 0.61248511 of a share of Lone Pine common stock for every share of Forest common stock held.

The table below sets forth the effects of changes in Forest’s ownership interest in Lone Pine on Forest’s equity, during the three and nine months ended September 30, 2011 when Forest had an ownership interest in Lone Pine.



	Three Months Ended September 30, 2011			Nine Months Ended September 30, 2011
	(In Thousands)
Net earnings attributable to Forest Oil Corporation common shareholders	$	82,795		$	118,375
Transfers from (to) the noncontrolling interest:
Increase in Forest Oil Corporation’s capital surplus for sale of 15 million Lone Pine Resources Inc. common shares	(269		)	112,610
Decrease in Forest Oil Corporation’s capital surplus for spin-off of 70 million Lone Pine Resources Inc. common shares	(333,568		)	(333,568		)
Change from net earnings attributable to Forest Oil Corporation and transfers from (to) noncontrolling interest	$	(251,042	)	$	(102,583	)

Lone Pine was a component of Forest with operations and cash flows clearly distinguishable, both operationally and for financial reporting purposes, from those of Forest. As a result of the spin-off, Lone Pine’s operations and cash flows have been eliminated from the ongoing operations of Forest, and Forest will not have any significant continuing involvement in the operations of Lone Pine. Accordingly, Forest has presented Lone Pine’s results of operations as discontinued operations in the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011.

The table below presents the major components of earnings from discontinued operations for the periods presented.



	Three Months Ended September 30, 2011			Nine Months Ended September 30, 2011
	(In Thousands)
	(Unaudited)
Total revenues	$	50,298		$	137,834
Production expenses	13,902			40,350
General and administrative	3,255			8,846
Depreciation, depletion, and amortization	20,799			60,780
Interest expense	3,000			3,866
Realized and unrealized gains on derivative instruments	(28,498		)	(33,628		)
Realized foreign currency exchange losses (gains)	23			(33,869		)
Unrealized foreign currency exchange (gains) losses, net	(52		)	28,488
Other, net	264			1,328
Earnings from discontinued operations before tax	37,605			61,673
Income tax	9,497			17,104
Net earnings from discontinued operations	$	28,108		$	44,569

(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Company’s 8½% senior notes due 2014, 7¼% senior notes due 2019, and 7½% senior notes due 2020 have been fully and unconditionally guaranteed by Forest Oil Permian Corporation (the “Guarantor Subsidiary”), a wholly-owned subsidiary of Forest. Forest’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, 2012 and December 31, 2011 and for the three and nine months ended September 30, 2012 and 2011 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Elimination entries presented are necessary to combine the entities.

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

(In Thousands)



	September 30, 2012												December 31, 2011
	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	$	39,098	$	—	$	71		$	—		$	39,169	$	1,734	$	1	$	1,277		$	—		$	3,012
Accounts receivable	46,533		26,978		4,161			(462		)	77,210		43,999		34,142		2,201			(1,253		)	79,089
Other current assets	59,190		319		622			—			60,131		127,667		313		591			—			128,571
Total current assets	144,821		27,297		4,854			(462		)	176,510		173,400		34,456		4,069			(1,253		)	210,672
Property and equipment	8,578,281		1,413,677		207,517			—			10,199,475		8,000,466		1,317,917		282,719			—			9,601,102
Less accumulated depreciation, depletion, and amortization	6,611,026		1,157,456		170,431			—			7,938,913		5,782,409		1,102,339		65,238			—			6,949,986
Net property and equipment	1,967,255		256,221		37,086			—			2,260,562		2,218,057		215,578		217,481			—			2,651,116
Investment in subsidiaries	80,577		—		—			(80,577		)	—		160,591		—		—			(160,591		)	—
Goodwill	216,460		22,960		—			—			239,420		216,460		22,960		—			—			239,420
Due from subsidiaries	145,817		58,730		—			(204,547		)	—		214,394		46,944		—			(261,338		)	—
Deferred income taxes	100,874		—		35,064			(126,087		)	9,851		312,564		—		25,564			(107,012		)	231,116
Other assets	96,035		—		—			—			96,035		48,827		—		—			—			48,827
	$	2,751,839	$	365,208	$	77,004		$	(411,673	)	$	2,782,378	$	3,344,293	$	319,938	$	247,114		$	(530,194	)	$	3,381,151
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	181,923	$	2,583	$	5,709		$	(462	)	$	189,753	$	235,788	$	8,846	$	4,499		$	(1,253	)	$	247,880
Current portion of long-term debt	296,002		—		—			—			296,002		—		—		—			—			—
Other current liabilities	61,574		129		6,313			—			68,016		86,618		63		6,276			—			92,957
Total current liabilities	539,499		2,712		12,022			(462		)	553,771		322,406		8,909		10,775			(1,253		)	340,837
Long-term debt	1,796,369		—		—			—			1,796,369		1,693,044		—		—			—			1,693,044
Due to parent and subsidiaries	—		—		204,547			(204,547		)	—		—		—		261,338			(261,338		)	—
Deferred income taxes	—		126,087		—			(126,087		)	—		—		107,012		—			(107,012		)	—
Other liabilities	173,194		3,650		12,617			—			189,461		135,730		2,614		15,813			—			154,157
Total liabilities	2,509,062		132,449		229,186			(331,096		)	2,539,601		2,151,180		118,535		287,926			(369,603		)	2,188,038
Shareholders’ equity	242,777		232,759		(152,182		)	(80,577		)	242,777		1,193,113		201,403		(40,812		)	(160,591		)	1,193,113
	$	2,751,839	$	365,208	$	77,004		$	(411,673	)	$	2,782,378	$	3,344,293	$	319,938	$	247,114		$	(530,194	)	$	3,381,151

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In Thousands)



	Three Months Ended September 30,
	2012															2011
	Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil, natural gas, and NGL sales	$	119,588		$	36,002		$	424		$	—		$	156,014		$	128,849		$	44,529		$	634		$	—		$	174,012
Interest and other	1,694			1,278			—			(2,918		)	54			348			76			—			(315		)	109
Equity earnings in subsidiaries	(73,712		)	—			—			73,712			—			39,093			—			—			(39,093		)	—
Total revenues	47,570			37,280			424			70,794			156,068			168,290			44,605			634			(39,408		)	174,121
Costs, expenses, and other:
Lease operating expenses	23,115			4,195			116			—			27,426			20,218			3,161			101			—			23,480
Other production expenses	12,546			(165		)	41			—			12,422			11,816			(735		)	42			—			11,123
General and administrative	12,341			689			386			—			13,416			18,672			881			389			—			19,942
Depreciation, depletion, and amortization	55,978			17,433			434			—			73,845			40,675			13,251			397			—			54,323
Ceiling test write-down of oil and natural gas properties	324,155			—			5,802			—			329,957			—			—			—			—			—
Impairment of properties	—			—			79,529			—			79,529			—			—			—			—			—
Interest expense	36,224			706			2,211			(2,918		)	36,223			37,225			(159		)	474			(315		)	37,225
Realized and unrealized losses (gains) on derivative instruments, net	17,883			4,848			64			—			22,795			(73,757		)	7,780			16			—			(65,961		)
Other, net	8,692			96			2,939			—			11,727			(1,895		)	186			1,532			—			(177		)
Total costs, expenses, and other	490,934			27,802			91,522			(2,918		)	607,340			52,954			24,365			2,951			(315		)	79,955
Earnings (loss) from continuing operations before income taxes	(443,364		)	9,478			(91,098		)	73,712			(451,272		)	115,336			20,240			(2,317		)	(39,093		)	94,166
Income tax	15,188			(842		)	(7,066		)	—			7,280			27,618			7,825			(887		)	—			34,556
Net earnings (loss) from continuing operations	(458,552		)	10,320			(84,032		)	73,712			(458,552		)	87,718			12,415			(1,430		)	(39,093		)	59,610
Net earnings from discontinued operations	—			—			—			—			—			—			—			28,108			—			28,108
Net earnings (loss)	(458,552		)	10,320			(84,032		)	73,712			(458,552		)	87,718			12,415			26,678			(39,093		)	87,718
Less: net earnings attributable to noncontrolling interest	—			—			—			—			—			—			—			4,923			—			4,923
Net earnings (loss) attributable to Forest Oil Corporation common shareholders	$	(458,552	)	$	10,320		$	(84,032	)	$	73,712		$	(458,552	)	$	87,718		$	12,415		$	21,755		$	(39,093	)	$	82,795

Comprehensive income (loss)	$	(458,367	)	$	10,320		$	(84,032	)	$	73,712		$	(458,367	)	$	49,577		$	12,415		$	26,678		$	(39,093	)	$	49,577

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (Continued)

(Unaudited)

(In Thousands)



	Nine Months Ended September 30,
	2012															2011
	Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil, natural gas, and NGL sales	$	326,209		$	123,093		$	1,307		$	—		$	450,609		$	382,211		$	142,775		$	1,929		$	—		$	526,915
Interest and other	3,381			1,850			—			(5,108		)	123			1,696			138			—			(895		)	939
Equity earnings in subsidiaries	(81,311		)	—			—			81,311			—			90,828			—			—			(90,828		)	—
Total revenues	248,279			124,943			1,307			76,203			450,732			474,735			142,913			1,929			(91,723		)	527,854
Costs, expenses, and other:
Lease operating expenses	69,087			12,774			306			—			82,167			60,487			9,789			317			—			70,593
Other production expenses	36,937			1,026			139			—			38,102			37,160			5,188			102			—			42,450
General and administrative	42,300			2,040			881			—			45,221			45,726			2,094			1,302			—			49,122
Depreciation, depletion, and amortization	157,381			55,116			1,305			—			213,802			115,738			38,193			1,296			—			155,227
Ceiling test write-down of oil and natural gas properties	673,131			—			40,619			—			713,750			—			—			—			—			—
Impairment of properties	—			—			79,529			—			79,529			—			—			—			—			—
Interest expense	103,932			894			4,214			(5,108		)	103,932			113,081			(351		)	1,246			(895		)	113,081
Realized and unrealized (gains) losses on derivative instruments, net	(33,044		)	(7,603		)	(97		)	—			(40,744		)	(77,929		)	7,282			15			—			(70,632		)
Other, net	35,259			293			6,550			—			42,102			8,354			165			3,761			—			12,280
Total costs, expenses, and other	1,084,983			64,540			133,446			(5,108		)	1,277,861			302,617			62,360			8,039			(895		)	372,121
Earnings (loss) from continuing operations before income taxes	(836,704		)	60,403			(132,139		)	81,311			(827,129		)	172,118			80,553			(6,110		)	(90,828		)	155,733
Income tax	165,694			19,075			(9,500		)	—			175,269			48,756			30,497			(2,313		)	—			76,940
Net earnings (loss) from continuing operations	(1,002,398		)	41,328			(122,639		)	81,311			(1,002,398		)	123,362			50,056			(3,797		)	(90,828		)	78,793
Net earnings from discontinued operations	—			—			—			—			—			—			—			44,569			—			44,569
Net earnings (loss)	(1,002,398		)	41,328			(122,639		)	81,311			(1,002,398		)	123,362			50,056			40,772			(90,828		)	123,362
Less: net earnings attributable to noncontrolling interest	—			—			—			—			—			—			—			4,987			—			4,987
Net earnings (loss) attributable to Forest Oil Corporation common shareholders	$	(1,002,398	)	$	41,328		$	(122,639	)	$	81,311		$	(1,002,398	)	$	123,362		$	50,056		$	35,785		$	(90,828	)	$	118,375

Comprehensive income (loss)	$	(1,001,840	)	$	41,328		$	(122,639	)	$	81,311		$	(1,001,840	)	$	95,910		$	50,056		$	40,772		$	(90,828	)	$	95,910

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)



	Nine Months Ended September 30,
	2012												2011
	Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidated			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidated
Operating activities:
Net earnings (loss)	$	(921,087	)	$	41,328		$	(122,639	)	$	(1,002,398	)	$	32,534		$	50,056		$	40,772		$	123,362
Less: net earnings from discontinued operations	—			—			—			—			—			—			44,569			44,569
Net earnings (loss) from continuing operations	(921,087		)	41,328			(122,639		)	(1,002,398		)	32,534			50,056			(3,797		)	78,793
Adjustments to reconcile net earnings (loss) from continuing operations to net cash provided (used) by operating activities of continuing operations:
Depreciation, depletion, and amortization	157,381			55,116			1,305			213,802			115,738			38,193			1,296			155,227
Deferred income tax	199,415			19,075			(9,500		)	208,990			18,540			30,497			(2,313		)	46,724
Unrealized losses (gains) on derivative instruments, net	37,698			8,565			109			46,372			(45,114		)	4,566			10			(40,538		)
Ceiling test write-down of oil and natural gas properties	673,131			—			40,619			713,750			—			—			—			—
Impairment of properties	—			—			79,529			79,529			—			—			—			—
Other, net	25,311			294			(2,026		)	23,579			30,018			243			(1,882		)	28,379
Changes in operating assets and liabilities:
Accounts receivable	4,657			7,164			(2,751		)	9,070			12,168			16,341			1,177			29,686
Other current assets	4,463			(6		)	(31		)	4,426			6,756			443			1,063			8,262
Accounts payable and accrued liabilities	1,915			(1,330		)	1,597			2,182			(7,118		)	787			1,235			(5,096		)
Accrued interest and other	(13,102		)	143			(518		)	(13,477		)	3,420			(122		)	679			3,977
Net cash provided (used) by operating activities of continuing operations	169,782			130,349			(14,306		)	285,825			166,942			141,004			(2,532		)	305,414
Investing activities:
Capital expenditures for property and equipment	(496,178		)	(99,814		)	(8,901		)	(604,893		)	(501,683		)	(89,477		)	(70,104		)	(661,264		)
Proceeds from sales of assets	8,902			—			—			8,902			120,949			—			7			120,956
Net cash used by investing activities of continuing operations	(487,276		)	(99,814		)	(8,901		)	(595,991		)	(380,734		)	(89,477		)	(70,097		)	(540,308		)
Financing activities:
Proceeds from bank borrowings	651,000			—			—			651,000			12,000			—			—			12,000
Repayments of bank borrowings	(756,000		)	—			—			(756,000		)	(12,000		)	—			—			(12,000		)
Issuance of senior notes, net of issuance costs	491,250			—			—			491,250			—			—			—			—
Change in bank overdrafts	(37,661		)	(213		)	158			(37,716		)	(20,979		)	185			134			(20,660		)
Net activity in investments from subsidiaries	8,480			(30,323		)	21,843			—			299,883			(51,715		)	(248,168		)	—
Other, net	(2,211		)	—			—			(2,211		)	(12,307		)	—			—			(12,307		)
Net cash provided (used) by financing activities of continuing operations	354,858			(30,536		)	22,001			346,323			266,597			(51,530		)	(248,034		)	(32,967		)
Cash flows from discontinued operations:
Operating cash flows	—			—			—			—			—			—			101,292			101,292
Investing cash flows	—			—			—			—			—			—			(255,470		)	(255,470		)
Financing cash flows	—			—			—			—			—			—			478,324			478,324
Net cash provided by discontinued operations	—			—			—			—			—			—			324,146			324,146
Effect of exchange rate changes on cash	—			—			—			—			—			—			(3,476		)	(3,476		)
Net increase (decrease) in cash and cash equivalents	37,364			(1		)	(1,206		)	36,157			52,805			(3		)	7			52,809
Net increase in cash and cash equivalents of discontinued operations	—			—			—			—			—			—			(289		)	(289		)
Net increase (decrease) in cash and cash equivalents of continuing operations	37,364			(1		)	(1,206		)	36,157			52,805			(3		)	(282		)	52,520
Cash and cash equivalents of continuing operations at beginning of period	1,734			1			1,277			3,012			216,580			3			986			217,569
Cash and cash equivalents of continuing operations at end of period	$	39,098		$	—		$	71		$	39,169		$	269,385		$	—		$	704		$	270,089

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(12) RECENT ACCOUNTING PRONOUNCEMENTS

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”), which requires that an entity disclose both gross and net information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement, including derivative instruments. ASU 2011-11 was issued in order to facilitate comparison of financial statements prepared under U.S. generally accepted accounting principles (“U.S. GAAP”) and International Financial Reporting Standards by requiring enhanced disclosures, but does not change existing U.S. GAAP, which permits balance sheet offsetting. This authoritative guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The adoption of this authoritative guidance will not have an impact on Forest’s financial position or results of operations, but will require Forest to make enhanced disclosures regarding its derivative instruments.

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

OVERVIEW

All expectations, forecasts, assumptions, and beliefs about our future financial results, condition, operations, strategic plans, and performance are forward-looking statements, as described in more detail under the heading “Forward-Looking Statements” below. Our actual results may differ materially because of a number of risks and uncertainties. Historical statements made herein are accurate only as of the date of filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”), and may be relied upon only as of that date. The following discussion and analysis should be read in conjunction with Forest’s Condensed Consolidated Financial Statements and the Notes thereto, the information included or incorporated by reference under the headings “Forward-Looking Statements” and “Risk Factors” below, and the information included or incorporated by reference in Forest’s 2011 Annual Report on Form 10-K under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Unless the context indicates otherwise, all references in this document to “Forest,” “the Company,” “we,” “our,” “ours,” and “us” refer to Forest Oil Corporation and its consolidated subsidiaries.

Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids primarily in the United States. 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. We currently conduct our operations in one material geographical segment: the United States. Our core operational areas are in the Texas Panhandle, the Eagle Ford Shale in South Texas, and the East Texas / North Louisiana area.

On June 1, 2011, Forest completed an initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which held Forest’s ownership interests in its Canadian operations. On September 30, 2011, Forest distributed, or spun-off, its remaining 82% ownership in Lone Pine to Forest’s shareholders, by means of a special stock dividend of Lone Pine common shares. As a result of the spin-off, Lone Pine’s results of operations and cash flows are reported as discontinued operations in Forest’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2011.

RESULTS OF OPERATIONS

The following table sets forth selected operating results for the three and nine months ended September 30, 2012 and 2011.



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012			2011
Net earnings (loss) from continuing operations (in thousands)	$	(458,552	)	$	59,610	$	(1,002,398	)	$	78,793
Diluted earnings (loss) per common share from continuing operations	$	(3.97	)	$	.52	$	(8.73	)	$	.69
Adjusted EBITDA from continuing operations (in thousands)⁽¹⁾	$	133,914		$	142,437	$	381,243		$	412,308

____________________________________________

(1)

In addition to reporting net earnings (loss) from continuing operations as defined under generally accepted accounting principles (“GAAP”), we also present Adjusted EBITDA from continuing operations, which is a non-GAAP performance measure. See “Reconciliation of Non-GAAP Measure” at the end of this Item 2 for a reconciliation of Adjusted EBITDA from continuing operations to reported net earnings (loss) from continuing operations, which is the most directly comparable financial measure calculated and presented in accordance with GAAP.

Forest recognized a net loss from continuing operations of $459 million and $1.0 billion for the three and nine months ended September 30, 2012, respectively, compared to net earnings from continuing operations of $60 million and $79 million in the corresponding periods in 2011. The decreases in each period were primarily due to non-cash ceiling test write-downs incurred during the three and nine months ended September 30, 2012 as well as valuation allowances placed against our deferred tax assets in each period in 2012. See Note 5 to the Condensed Consolidated Financial Statements for more details on ceiling test write-downs, which apply to companies that follow the full cost method of accounting for oil and gas activities. See Critical Accounting Policies for more details on the valuation allowances on deferred tax assets.

Adjusted EBITDA from continuing operations, which excludes the effects of ceiling test write-downs, changes in valuation allowances, and other non-cash items, decreased $9 million and $31 million during the three and nine months ended

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September 30, 2012, respectively, as compared to the corresponding periods in 2011. The $9 million decrease between the corresponding three-month periods was primarily due to an increase in production and other expenses. Oil, natural gas, and NGL revenues also decreased between the comparable three-month periods, but the decrease was equally offset by an increase in realized gains from hedging activities. The $31 million decrease between the comparable nine-month periods was due to decreases in natural gas and NGL revenues, which were partially offset by an increase in oil revenues, due to increased volumes, and an increase in realized hedge gains.

Management’s analysis of the individual components of the changes in our quarterly and year-to-date results follows.

Oil, Natural Gas, and Natural Gas Liquids Volumes and Revenues

Oil, natural gas, and natural gas liquids (“NGL”) sales volumes, revenues, and average sales prices from continuing operations for the three and nine months ended September 30, 2012 and 2011 are set forth in the table below.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Sales volumes:
Oil (MBbls)	820		638		2,345		1,748
Natural gas (MMcf)	20,694		21,774		62,459		66,600
NGL (MBbls)	930		689		2,646		2,309
Totals (MMcfe)	31,194		29,736		92,405		90,942
Revenues (in thousands):
Oil	$	77,359	$	58,610	$	229,101	$	167,189
Natural gas	51,241		84,158		137,962		258,700
NGL	27,414		31,244		83,546		101,026
Totals	$	156,014	$	174,012	$	450,609	$	526,915
Average sales price per unit:
Oil ($/Bbl)	$	94.34	$	91.87	$	97.70	$	95.65
Natural gas ($/Mcf)	2.48		3.87		2.21		3.88
NGL ($/Bbl)	29.48		45.35		31.57		43.75
Totals ($/Mcfe)	$	5.00	$	5.85	$	4.88	$	5.79

Our equivalent sales volumes from continuing operations increased 5% and 2% for the three and nine months ended September 30, 2012, respectively, compared to the corresponding periods in 2011. Additionally, total oil and NGL sales volumes increased to 34% and 32% of total equivalent sales volumes in the three and nine months ended September 30, 2012, respectively, as compared to 27% of total equivalent sales volumes in both the three and nine months ended September 30, 2011. The increase in the percentages is a result of drilling more oil and natural gas liquids-rich wells.

Revenues from oil, natural gas, and NGLs were $156 million in the third quarter of 2012 compared to $174 million in the third quarter of 2011. The $18 million decrease was primarily a result of a 36% decline in the market price for natural gas, with this decrease being partially offset by an increase in oil volumes and the market price for oil. Revenues from oil, natural gas, and NGLs were $451 million in the first nine months of 2012 compared to $527 million in the first nine months of 2011. The $76 million decrease between the comparable nine month periods was primarily due to a 43% decrease in natural gas market prices as well as a decrease in NGL market prices, with such decreases being partially offset by a $62 million increase in oil revenues, resulting primarily from a 34% increase in our oil sales volumes.

The revenues and average sales prices reflected in the table above exclude the effects of commodity derivative instruments because we have elected not to designate our derivative instruments as cash flow hedges. See “Realized and Unrealized Gains and Losses on Derivative Instruments” below for more information on gains and losses relating to our commodity derivative instruments.

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Production Expense

The table below sets forth the detail of production expense from continuing operations for the periods indicated.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(In Thousands, Except Per Mcfe Data)
Production expense:
Lease operating expenses	$	27,426	$	23,480	$	82,167	$	70,593
Production and property taxes	8,842		7,926		26,935		32,187
Transportation and processing costs	3,580		3,197		11,167		10,263
Production expense	$	39,848	$	34,603	$	120,269	$	113,043
Production expense per Mcfe:
Lease operating expenses	$	.88	$	.79	$	.89	$	.78
Production and property taxes	.28		.27		.29		.35
Transportation and processing costs	.11		.11		.12		.11
Production expense per Mcfe	$	1.28	$	1.16	$	1.30	$	1.24

Lease Operating Expenses

Lease operating expenses in the third quarter of 2012 were $27 million, or $.88 per Mcfe, compared to $23 million, or $.79 per Mcfe, in the third quarter of 2011. Lease operating expenses in the first nine months of 2012 were $82 million, or $.89 per Mcfe, compared to $71 million, or $.78 per Mcfe, in the first nine months of 2011. The increases in lease operating expenses in the 2012 periods as compared to the 2011 periods were primarily due to increases in water disposal costs and workovers as well as an increase in the number of oil wells. Based on the energy-equivalent ratio of six Mcf of natural gas to one of barrel of oil, oil wells typically have higher per-unit lease operating costs than do natural gas wells. However, because the market price of oil relative to natural gas is currently well in excess of the six-to-one ratio, the increase in lease operating expense associated with more oil production is more than offset by the additional revenues from oil sales.

Production and Property Taxes

Production and property taxes, consisting primarily of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 5.7% and 4.6% of oil, natural gas, and NGL sales for the three-month periods ended September 30, 2012 and 2011, respectively, and 6.0% and 6.1% for the nine-month periods ended September 30, 2012 and 2011, respectively. Normal fluctuations occur in this 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 oil and gas properties and equipment for purposes of ad valorem taxes.

Transportation and Processing Costs

Transportation and processing costs in the third quarter of 2012 were $4 million, or $.11 per Mcfe, compared to $3 million, or $.11 per Mcfe, in the third quarter of 2011. Transportation and processing costs in the first nine months of 2012 were $11 million, or $.12 per Mcfe, compared to $10 million, or $.11 per Mcfe, in the first nine months of 2011.

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General and Administrative Expense

The table below sets forth the components of general and administrative expense from continuing operations for the periods indicated.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In Thousands)
Stock-based compensation costs	$	5,766		$	15,999		$	19,140		$	28,938
Stock-based compensation costs capitalized	(2,292		)	(7,167		)	(6,509		)	(12,189		)
	3,474			8,832			12,631			16,749

Other general and administrative costs	16,949			19,767			55,696			58,096
Other general and administrative costs capitalized	(7,007		)	(8,657		)	(23,106		)	(25,723		)
	9,942			11,110			32,590			32,373

General and administrative expense	$	13,416		$	19,942		$	45,221		$	49,122

General and administrative expense was $13 million in the third quarter of 2012 compared to $20 million in the third quarter of 2011, and it was $45 million in the first nine months of 2012 compared to $49 million in the first nine months of 2011. The decrease in stock-based compensation costs for both the 2012 periods as compared to the 2011 periods is primarily due to the $12 million in stock-based compensation costs ($7 million of expense, net of capitalized amounts) recognized during the third quarter of 2011 related to the spin-off of Lone Pine. The spin-off caused the forfeiture restrictions to lapse on a portion of each outstanding restricted stock award, thus requiring the immediate recognition of compensation cost. For the nine months ended September 30, 2012, the decrease in stock-based compensation costs discussed above was partially offset by $5 million in accelerated stock-based compensation costs ($4 million of expense, net of capitalized amounts) related to the termination of our former chief executive officer, which was recognized during the second quarter of 2012. The percentage of general and administrative costs capitalized under the full cost method of accounting ranged from 40% to 44% in the periods presented.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization expense (“DD&A”) in the third quarter of 2012 was $74 million, or $2.37 per Mcfe, compared to $54 million, or $1.83 per Mcfe, in the third quarter of 2011. For the first nine months of 2012, DD&A was $214 million, or $2.31 per Mcfe, compared to $155 million, or $1.71 per Mcfe, for the first nine months of 2011. DD&A has increased in each 2012 period due primarily to the increase in oil reserve additions since 2011, which typically have higher per-unit development costs than natural gas reserves. In addition, in 2012, a portion of our proved undeveloped natural gas reserves, which have lower associated development costs than do proved undeveloped oil reserves, have been reclassified from proved to probable status in conjunction with the decrease in the natural gas prices used to determine our proved reserves. This reclassification also contributed to the increase in our DD&A rate.

Ceiling Test Write-Down of Oil and Natural Gas Properties

In the second and third quarters of 2012, we recorded ceiling test write-downs of our United States cost center of $349 million and $330 million, respectively, pursuant to the ceiling test limitation prescribed by the SEC for companies using the full cost method of accounting. These ceiling test write-downs were primarily a result of the decline in the twelve-month arithmetic average prices of natural gas and NGL that were used to calculate the present value of future net revenues from our estimated proved oil and natural gas reserves at the end of the last two calendar quarters. Additional write-downs of our oil and natural gas properties may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenue from estimated production of proved oil and natural gas reserves decline compared to prices used as of September 30, 2012, unproved property values decrease, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center.

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In April 2012, an Italian regional regulatory body concluded its review of our environmental impact assessment (“EIA”) and denied approval. Approval of the EIA is necessary in order for us to commence production in Italy. We are currently appealing the region’s denial. In the meantime, however, we determined that we can no longer conclude with reasonable certainty that our Italian natural gas reserves are producible and, therefore, those reserves can no longer be classified as proved reserves. The Italian reserves are now classified as probable. Since we received this ruling prior to issuing our March 31, 2012 financial statements, we recorded a ceiling test write-down of our Italian cost center for the three months ended March 31, 2012 of $35 million.

Impairment of Properties

During the quarter ended September 30, 2012, we recorded a $67 million impairment of our unproved properties in South Africa upon the determination that we would likely not recover the carrying amount of our investment in these properties. This determination was based on several unsuccessful attempts to sell the properties. Because we have no proved reserves in South Africa, the impairment was reported as a period expense rather than being added to the costs to be amortized and is included in the Condensed Consolidated Statements of Operations within the “Impairment of properties” line item.

In August 2012, we entered into an agreement to sell the majority of our East Texas natural gas gathering assets for $34 million in cash. We can also earn up to $9 million of additional performance payments contingent on future activity. The transaction is expected to close on October 31, 2012 and is subject to customary closing conditions and purchase price adjustments, including effective date and title defect adjustments. In conjunction with the sale, we entered into a ten-year natural gas gathering agreement with the buyer under which we will pay market-based gathering rates and commit the production from our existing and future operated wells located within five miles of the current configuration of the gathering system. As of September 30, 2012, these assets are presented in the Condensed Consolidated Balance Sheet as assets held for sale and were written down to their estimated fair value less cost to sell, with a $13 million impairment charge included in the Condensed Consolidated Statements of Operations within the “Impairment of properties” line item. Since there will be a continuation of cash flows between Forest and the disposed component by way of the natural gas gathering agreement, these assets do not qualify for discontinued operations reporting. We intend to use the proceeds from this divestiture to repay outstanding borrowings under our bank credit facility.

Interest Expense

The table below sets forth interest expense from continuing operations for the periods indicated.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In Thousands)
Interest costs	$	37,913		$	40,269		$	109,719		$	120,590
Interest costs capitalized	(1,690		)	(3,044		)	(5,787		)	(7,509		)
Interest expense	$	36,223		$	37,225		$	103,932		$	113,081

Interest expense was $36 million in the third quarter of 2012 compared to $37 million in the third quarter of 2011. Interest expense was $104 million and $113 million for the nine months ended September 30, 2012 and 2011, respectively. The decreases of $1 million and $9 million, respectively, in the comparable three and nine month periods were primarily attributable to the redemption of $285 million of 8% senior notes in December of 2011, partially offset by an increase in interest costs incurred on borrowings under our bank credit facility in 2012, interest costs on the 7½% senior notes issued in September 2012, and lower capitalized interest in 2012.

In order to effectively reduce our concentration of fixed-rate debt, we have entered into fixed-to-floating interest rate swaps under which we have swapped, as of September 30, 2012, $500 million in notional amount at an 8.5% fixed rate for an equal notional amount at a weighted-average interest rate equal to the 1-month LIBOR plus approximately 5.9%. We recognized realized gains under these interest rate swaps of $3 million and $8 million during the three and nine months ended September 30, 2012, respectively, and $3 million and $9 million during the three and nine months ended September 30, 2011, respectively. These gains are recorded as realized gains on derivatives rather than as a reduction in interest expense since we have not elected to use hedge accounting. See Note 8 to the Condensed Consolidated Financial Statements for more information on our interest rate derivatives.

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Realized and Unrealized Gains and Losses on Derivative Instruments

The table below sets forth realized and unrealized gains and losses on derivative instruments from continuing operations 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.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In Thousands)
Realized (gains) losses on derivative instruments, net:
Oil	$	(2,097	)	$	1,335		$	(2,112	)	$	9,867
Natural gas	(22,664		)	(17,708		)	(75,172		)	(51,582		)
NGL	(1,481		)	7,734			(1,353		)	20,237
Interest	(2,758		)	(2,774		)	(8,479		)	(8,616		)
Subtotal realized gains on derivative instruments, net	(29,000		)	(11,413		)	(87,116		)	(30,094		)
Unrealized losses (gains) on derivative instruments, net:
Oil	8,390			(23,696		)	(1,129		)	(22,751		)
Natural gas	39,087			(20,726		)	49,554			(13,441		)
NGL	2,754			(7,464		)	(6,766		)	79
Interest	1,564			(2,662		)	4,713			(4,425		)
Subtotal unrealized losses (gains) on derivative instruments, net	51,795			(54,548		)	46,372			(40,538		)
Realized and unrealized losses (gains) on derivative instruments, net	$	22,795		$	(65,961	)	$	(40,744	)	$	(70,632	)

Other, Net

The table below sets forth the components of “Other, net” from continuing operations for the periods indicated.



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012		2011			2012		2011
	(In Thousands)
Accretion of asset retirement obligations	$	1,719	$	1,539		$	4,914	$	4,496
Legal proceeding liabilities	6,404		—			29,251		6,500
Other, net	3,604		(1,716		)	7,937		1,284
	$	11,727	$	(177	)	$	42,102	$	12,280

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. Our asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and natural gas properties. See Note 9 to the Condensed Consolidated Financial Statements for a discussion of the legal proceeding liabilities.

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Income Tax

The table below sets forth the current and deferred components of income tax and the effective income tax rates related to continuing operations for the periods indicated.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In Thousands, Except Percentages)
Current income tax	$	(33,830	)	$	1,172		$	(33,721	)	$	30,216
Deferred income tax	41,110			33,384			208,990			46,724
Total income tax	$	7,280		$	34,556		$	175,269		$	76,940
Effective income tax rate	(2		)%	37		%	(21		)%	49		%

Our effective income tax rate was (2)% and (21)% for the three and nine months ended September 30, 2012, respectively, and 37% and 49% for the three and nine months ended September 30, 2011, respectively. The significant difference between our United States federal statutory income tax rate of 35% and our effective income tax rate of (2)% and (21)% for the three and nine months ended September 30, 2012, respectively, was primarily due to changes in valuation allowances on our deferred tax assets of $170 million and $473 million for the three and nine months ended September 30, 2012, respectively. Without these changes to the valuation allowances, our effective income tax rates would have been 36% in each of the 2012 periods presented. The difference between our effective and statutory income tax rate for the nine months ended September 30, 2011 was primarily due to a Canadian dividend tax of $29 million that was incurred on a stock dividend declared and paid by our former Canadian subsidiary, Lone Pine Resources Canada Ltd. (“LPR Canada”), to Forest, as parent, immediately before Forest’s contribution of LPR Canada to Lone Pine in conjunction with Lone Pine’s initial public offering. See Note 6 to the Condensed Consolidated Financial Statements for a reconciliation of income tax computed using the federal statutory income tax rate to income tax computed using our effective income tax rate for each period presented, and “Critical Accounting Policies, Estimates, Judgments, and Assumptions—Valuation of Deferred Tax Assets” for more information on our income taxes and valuation allowance. We recorded a $34 million current income tax benefit in the three months ended September 30, 2012, which was primarily due to an income tax refund we filed for in September 2012 related to cash taxes paid in 2009 and 2010. This refund receivable is included in “Other assets” in the Condensed Consolidated Balance Sheet as of September 30, 2012.

Discontinued Operations

The results of operations of Lone Pine are presented as discontinued operations in Forest’s Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 due to the spin-off of Lone Pine on September 30, 2011. See Note 10 to the Condensed Consolidated Financial Statements for more information regarding the components of earnings from discontinued operations.

LIQUIDITY AND CAPITAL RESOURCES

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 facility as our primary sources of liquidity. To fund large 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, natural gas, and natural gas liquids directly impact our level of cash flow generated from operations. For the nine months ended September 30, 2012, natural gas accounted for approximately 68% of our total 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 prices for oil and natural gas liquids. 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 24, 2012, we had hedged, via commodity swaps, approximately 67 Bcfe of our total projected 2012 production, approximately 67 Bcfe of our total projected 2013 production, and approximately 15 Bcf of our total projected 2014 production, excluding the volumes underlying outstanding unexercised commodity swaptions and put options. This level of hedging will provide a measure of certainty with respect to the cash flow that we will receive for a portion of our future production. However, these hedging activities may result in reduced income or even financial losses to us. In the future, we may determine to increase or decrease

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our hedging positions. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” below for more information on our derivative contracts including commodity swaptions and put options.

As noted above, the other primary source of liquidity is our bank credit facility, which currently has a borrowing base of $1.15 billion. This facility is used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facility is secured by a portion of our assets, with the facility maturing in June 2016. See “Bank Credit Facility” below for further details. We had no borrowings outstanding under our credit facility as of September 30, 2012 and had $279 million in borrowings outstanding under our credit facility as of October 24, 2012.

The public and private capital markets have served as our primary source of financing to fund large acquisitions and other exceptional transactions. In the past, we have issued debt and equity in both the public and private capital markets. For example, we completed a private offering of $500 million of senior notes in September 2012, using some of the proceeds to redeem $300 million of existing senior notes. 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.

We believe that our cash flows provided by operating activities and the funds available under our credit facility will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures, and our contractual obligations. However, if our revenue and cash flow decrease as a result of a deterioration in domestic and global economic conditions, a significant decline in commodity prices, or a continuation of depressed natural gas prices, we may elect to reduce our planned capital expenditures, as we have in the second half of 2012. We believe that this financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations.

Bank Credit Facility

On June 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the ‘‘Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A., consisting of a $1.5 billion credit facility maturing in June 2016. Subject to the agreement of us and the applicable lenders, the size of the Credit Facility may be increased by $300 million, to a total of $1.8 billion.

Our availability under the Credit Facility is governed by a borrowing base. As of September 30, 2012, the borrowing base under the Credit Facility was $1.20 billion. The determination of the 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 Facility could increase or decrease based on such redetermination. The lenders completed their most recent scheduled semi-annual redetermination of the borrowing base, reducing it to $1.15 billion effective October 5, 2012. The next scheduled semi-annual redetermination of the borrowing base will occur on or about May 1, 2013. In addition to the scheduled semi-annual redeterminations, we and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined.

The borrowing base is also subject to change in the event (i) we or our Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that we or any of our Restricted Subsidiaries may issue to refinance then-existing senior notes, or (ii) we or our Restricted Subsidiaries sell oil and natural gas properties included in the borrowing base having a fair market value in excess of 10% of the borrowing base then in effect. Due to the September 2012 issuance of senior unsecured notes that did not refinance then-existing senior notes, our borrowing base was reduced by $50 million effective September 17, 2012. In addition, we expect our borrowing base will be automatically reduced by approximately $80 million upon the closing of our $220 million south Louisiana property sale discussed in Note 5 to the Condensed Consolidated Financial Statements. If the borrowing base is reduced to a level that is below our level of borrowing under the Credit Facility, we would be required to repay indebtedness in excess of the borrowing base in order to cover the deficiency.

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

(i)

the greatest of (a) the prime rate announced by JPMorgan Chase Bank, N.A., (b) the federal funds effective rate from time to time plus ½ of 1%, and (c) the one-month rate applicable to dollar deposits in the London interbank market for one, two, three or six months (as selected by us) (the “LIBO Rate”) plus 1%, plus, in the case of each of clauses (a), (b), and (c), 50 to 150 basis points depending on borrowing base utilization; or


(ii)	the LIBO Rate as adjusted for statutory reserve requirements (the “Adjusted LIBO Rate”), plus 150 to 250 basis points, depending on borrowing base utilization.

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant. The Credit Facility provides that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.5 to 1.0 at any time. Our ratio of total debt outstanding to EBITDA for the twelve-month period ended September 30, 2012, as calculated in accordance with the Credit Facility, was 4.2. We expect to continue to meet this covenant by maintaining our capital expenditures at or below our cash flows from operating activities in subsequent quarters and by using proceeds from the sale of non-core assets to reduce debt. See Note 5 to the Condensed Consolidated Financial Statements for more information on our anticipated divestitures.

Under certain conditions, amounts outstanding under the Credit Facility may be accelerated. Bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility. Subject to notice and cure periods, certain events of default under the Credit Facility will result in acceleration of the indebtedness under the Credit Facility at the option of the lenders. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the Credit Facility (including the financial covenant), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility.

The Credit Facility is collateralized by our assets. Under the Credit Facility, we are required to mortgage and grant a security interest in 75% of the present value of our and our U.S. subsidiaries’ estimated proved oil and gas properties and related assets. We are required to pledge, and have pledged, the stock of certain subsidiaries to secure the Credit Facility. If our corporate credit rating by Moody’s and S&P meet pre-established levels, the security requirements would cease to apply and, at our request, the banks would release their liens and security interest on our properties.

At September 30, 2012, there were no outstanding borrowings under the Credit Facility and we had used the Credit Facility for $2 million in letters of credit. At October 24, 2012, there were outstanding borrowings of $279 million under the Credit Facility at a weighted average interest rate of 1.9%, and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $869 million.

From time to time, we engage in other transactions with a number of the lenders under the Credit Facility. Such lenders or their affiliates may serve as underwriters or initial purchasers of our debt and equity securities, or directly purchase our production, or serve as counterparties to our commodity and interest rate derivative agreements. As of October 24, 2012, all but one of our derivative instrument counterparties are lenders, or their affiliates, under our Credit Facility. Our obligations under our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our Credit Facility. See Item 3, ‘‘Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk’’ below for additional details concerning our derivative arrangements.

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Historical Cash Flow

Net cash provided by operating activities of continuing operations, net cash used by investing activities of continuing operations, and net cash provided (used) by financing activities of continuing operations for the nine months ended September 30, 2012 and 2011 were as follows:



	Nine Months Ended
	September 30,
	2012			2011
	(In Thousands)
Net cash provided by operating activities of continuing operations	$	285,825		$	305,414
Net cash used by investing activities of continuing operations	(595,991		)	(540,308		)
Net cash provided (used) by financing activities of continuing operations	346,323			(32,967		)

Net cash provided by operating activities of continuing operations is primarily affected by sales volumes and commodity prices, net of the effects of settlements of our derivative contracts and changes in working capital. The decrease in net cash provided by operating activities of continuing operations in the nine months ended September 30, 2012, compared to the same period of 2011, was primarily due to decreased revenue, which was caused primarily by lower natural gas and NGL prices, and increased investment in net operating assets (i.e., working capital), partially offset by higher realized gains on commodity derivative instruments and an increase in oil sales volumes.

The components of net cash used by investing activities of continuing operations for the nine months ended September 30, 2012 and 2011 were as follows:



	Nine Months Ended
	September 30,
	2012			2011
	(In Thousands)
Exploration, development, and leasehold acquisition costs⁽¹⁾	$	(598,882	)	$	(656,894	)
Proceeds from sale of assets	8,902			120,956
Other fixed asset costs	(6,011		)	(4,370		)
Net cash used by investing activities of continuing operations	$	(595,991	)	$	(540,308	)

____________________________________________

(1)

Cash paid for exploration, development, and leasehold acquisition costs as reflected in the Condensed Consolidated Statements of Cash Flows differs from the reported capital expenditures in the “Capital Expenditures” table below due to the timing of when the capital expenditures are incurred and when the actual cash payment is made, as well as non-cash capital expenditures such as capitalized stock-based compensation costs and common stock issued for the acquisition of oil and natural gas properties.

Net cash used by investing activities of continuing operations is primarily comprised of expenditures for the acquisition, exploration, and development of oil and natural gas properties, net of proceeds from the dispositions of oil and natural gas properties and other capital assets. The increase in net cash used by investing activities of continuing operations in the nine months ended September 30, 2012, compared to the same period of 2011, was primarily due to a decrease in proceeds from the sale of assets partially offset by a decrease in exploration, development, and leasehold acquisition cost expenditures during the nine months ended September 30, 2012.

The increase in net cash provided by financing activities of continuing operations in the nine months ended September 30, 2012, compared to the same period of 2011, was primarily due to the issuance of the 7½% senior notes due 2020 for net proceeds of $491 million, after deducting initial purchaser discounts. This increase was partially offset by net repayments of bank borrowings of $105 million during the nine months ended September 30, 2012 and a $17 million change in the change in bank overdrafts between the two periods.

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Capital Expenditures

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



	Nine Months Ended
	September 30,
	2012		2011
	(In Thousands)
Exploration, development, and acquisition costs:
Direct costs:
Exploration and development	$	526,936	$	481,901
Leasehold acquisitions	60,769		182,147
Overhead capitalized	29,615		37,912
Interest capitalized	5,787		7,509
Total capital expenditures⁽¹⁾	$	623,107	$	709,469

____________________________________________

(1)

Total capital expenditures include cash expenditures, accrued expenditures, and non-cash capital expenditures including the value of common stock issued for oil and natural gas property acquisitions and stock-based compensation capitalized under the full cost method of accounting. Total capital expenditures also include changes in estimated discounted asset retirement obligations of $5 million and $3 million recorded during the nine months ended September 30, 2012 and 2011, respectively.

We estimate that our capital expenditures for 2012 will be between $673 million and $693 million (excluding capitalized interest, capitalized stock-based compensation, and asset retirement obligations incurred). During the fourth quarter of 2012, we expect that our capital spending will be approximately equal to our expected cash flows based on current commodity prices. Our remaining 2012 capital budget mainly targets higher-margin oil opportunities, and we have reduced spending in, and expect to have lower production from, lower-return natural gas liquids and natural gas projects.

CRITICAL ACCOUNTING POLICIES, ESTIMATES, JUDGMENTS, AND ASSUMPTIONS

Reference should be made to our 2011 Annual Report on Form 10-K under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions” for a discussion of other critical accounting policies in addition to that discussed below.

Valuation of Deferred Tax Assets

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

In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. In making this assessment, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies, and projected future taxable income. If the ultimate realization of deferred tax assets is dependent upon future book income, assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive, as to whether it is more likely than not that a deferred tax asset will be realized.

Negative evidence considered by management included a three-year cumulative book loss driven primarily by the ceiling test write-downs incurred in the second and third quarters of 2012. Positive evidence considered by management included forecasted book income in future years based on expected future oil, natural gas, and NGL production and expected commodity prices based on NYMEX oil and natural gas futures. Based upon the evaluation of what management determined to be relevant evidence, we have recorded a valuation allowance of $473 million against our U.S. deferred tax assets as of September 30, 2012. Although we expect future book income based on future production and future NYMEX oil and natural gas prices, oil and natural gas prices have been highly volatile over recent years, and only a portion of our forecasted production is hedged for the remainder of 2012 and through the end of 2014.

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FORWARD-LOOKING STATEMENTS

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,” the negative of such words or other variations of such words, and similar expressions identify forward-looking statements. Similarly, statements that describe our strategies, initiatives, objectives, plans, or goals are forward-looking. These forward-looking statements are based on our current intent, belief, expectations, estimates, projections, forecasts, and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These statements are not guarantees of future performance.

These forward-looking statements appear in a number of places and include statements with respect to, among other things:


•	estimates of our oil and natural gas reserves;


•	estimates of our future oil and natural gas production, including estimates of any increases or decreases in our production;


•	our future financial condition and results of operations;


•	our future revenues, cash flows, and expenses;


•	our access to capital and our anticipated liquidity;


•	our future business strategy and other plans and objectives for future operations;


•	our outlook on oil and natural gas prices;


•	the amount, nature, and timing of future capital expenditures, including future development costs;


•	our ability to access the capital markets to fund capital and other expenditures;


•	our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and


•	the impact of federal, state, and local political, regulatory, and environmental developments in the United States and certain foreign locations where we conduct business operations.

We believe the expectations, estimates, projections, forecasts, and assumptions 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 involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations and projections. 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 2011 Annual Report on Form 10-K and the risks incorporated in Part II, Item 1A, “Risk Factors” in this Form 10-Q.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information to reflect events or circumstances after the filing of this report with the SEC, except as required by law. All forward-looking statements, expressed or implied, included in this Form

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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.

RECONCILIATION OF NON-GAAP MEASURE

Adjusted EBITDA

In addition to reporting net earnings (loss) from continuing operations as defined under GAAP, we also present adjusted earnings from continuing operations before interest, income taxes, depreciation, depletion, and amortization and certain other items (“Adjusted EBITDA”), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings (loss) from continuing operations before interest expense, income taxes, depreciation, depletion, and amortization, as well as other non-cash operating items such as unrealized gains and losses on derivative instruments, ceiling test write-downs of oil and natural gas properties, 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) from continuing operations (its most comparable GAAP financial measure), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating interest, taxes, depreciation, depletion, amortization, and other items from earnings, we believe the result is a useful measure across time in evaluating our fundamental core operating performance. Management also uses Adjusted EBITDA to manage its business, including in preparing its annual operating budget and financial projections. We believe 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. Our management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) from continuing operations and revenues to measure operating performance. The following table provides a reconciliation of net earnings (loss) from continuing operations, the most directly comparable GAAP measure, to Adjusted EBITDA for the periods presented.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In Thousands)
Net earnings (loss) from continuing operations	$	(458,552	)	$	59,610		$	(1,002,398	)	$	78,793
Income tax expense	7,280			34,556			175,269			76,940
Unrealized losses (gains) on derivative instruments, net	51,795			(54,548		)	46,372			(40,538		)
Interest expense	36,223			37,225			103,932			113,081
Accretion of asset retirement obligations	1,719			1,539			4,914			4,496
Ceiling test write-down of oil and natural gas properties	329,957			—			713,750			—
Impairment of properties	79,529			—			79,529			—
Depreciation, depletion, and amortization	73,845			54,323			213,802			155,227
Stock-based compensation	2,970			9,732			12,227			17,809
Legal proceeding/severance costs	6,404			—			31,102			6,500
Rig stacking	2,744			—			2,744			—
Adjusted EBITDA from continuing operations	$	133,914		$	142,437		$	381,243		$	412,308

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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.

Commodity Price Risk

We produce and sell natural gas, crude oil, and NGLs in the United States. 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, and other derivative instruments with counterparties who, in general, are participants in our Credit Facility. 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.

Swaps

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 than the fixed price, 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, 2012, we had entered into the following swaps:



Commodity Swaps
	Natural Gas (NYMEX HH)					Oil (NYMEX WTI)					NGL (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)
October 2012 - December 2012⁽¹⁾	155	$	4.63	$	18,655	4,500	$	97.26	$	1,868	2,000	$	45.22	$	1,370
Calendar 2013	160	3.98		7,821		4,000	95.53		2,624		—	—		—

_____________________________

(1)

50 Bbtu per day of 2012 gas swaps with a weighted average hedged price per MMBtu of $5.30 are layered with a written put of $3.53 and a call spread of $4.00 to $4.50. Together with the put and call spread, we will receive the $5.30 swap price on 50 Bbtu per day except as follows: we will receive (i) NYMEX HH plus $1.77 when NYMEX HH is below $3.53; (ii) $5.30 plus the value of the call spread when NYMEX HH is between $4.00 and $4.50; and (iii) $5.80 when NYMEX HH is $4.50 or above. The fair value of the written put and call spread derivative instruments as of September 30, 2012 was a liability of $1 million.

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Commodity Options

In connection with several natural gas and oil swaps entered into, we granted option instruments (several commodity swaptions and puts) to the swap counterparties in exchange for our receiving premium hedged prices on the natural gas and oil swaps. Under the terms of our commodity swaption agreements, the counterparties have the right, but not the obligation, to enter into a specified swap agreement with us before the option expires. The table below sets forth key provisions of the outstanding options as of September 30, 2012. (As of October 24, 2012, none of the options in the table have been exercised by the counterparties.)



Commodity Options
		Natural Gas (NYMEX HH)						Oil (NYMEX WTI)
Underlying Term	Option Expiration	Underlying Bbtu Per Day	Underlying Hedged Price per MMBtu		Fair Value (In Thousands)			Underlying Barrels Per Day	Underlying Hedged Price per Bbl		Fair Value (In Thousands)
Gas Swaptions:
Calendar 2013	December 2012	30	$	4.02	$	(1,721	)	—	$	—	$	—
Calendar 2013	December 2012	10	4.01		(588		)	—	—		—
Oil Swaptions:
Calendar 2013	December 2012	—	—		—			2,000	95.00		(3,516		)
Calendar 2014	December 2013	—	—		—			2,000	110.00		(2,762		)
Calendar 2014	December 2013	—	—		—			1,000	109.00		(1,437		)
Calendar 2014	December 2013	—	—		—			2,000	100.00		(4,590		)
Calendar 2015	December 2014	—	—		—			3,000	100.00		(7,329		)
Oil Put Options:
Monthly Oct - Dec 2012	Monthly Oct - Dec 2012	—	—		—			5,000	75.00		(137		)

The estimated fair value at September 30, 2012 of all our commodity derivative instruments based on various inputs, including published forward prices, was a net asset of approximately $9 million.

Derivative Instruments Entered Into Subsequent to September 30, 2012

Subsequent to September 30, 2012, through October 24, 2012, we entered into the following derivative agreements:



Commodity Swaps
	Natural Gas (NYMEX HH)
Swap Term	Bbtu Per Day	Weighted Average Hedged Price per MMBtu
Calendar 2014⁽¹⁾	40	$	4.50

____________________________________


(1)	In connection with entering into these natural gas swaps with premium hedged prices, Forest granted options to the counterparties to enter into gas swaps with Forest for Calendar 2014 covering 40 Bbtu per day at a weighted average hedged price per MMBtu of $4.50, with such options expiring in December 2013.

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Interest Rate Risk

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, 2012, we had entered into the following fixed-to-floating interest rate swaps:



Interest Rate Swaps
Remaining Swap Term	Notional Amount (In Thousands)		Weighted Average Floating Rate	Weighted Average Fixed Rate		Fair Value (In Thousands)
October 2012 - February 2014	$	500,000	1 month LIBOR + 5.89%	8.50	%	$	15,844

The estimated fair value of all our interest rate derivative instruments was a net asset of approximately $16 million as of September 30, 2012.

Derivative Fair Value Reconciliation

The table below sets forth the changes that occurred in the fair values of our derivative contracts during the nine months ended September 30, 2012, beginning with the fair value of our derivative contracts on December 31, 2011. 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, natural gas, and NGL 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, 2012 and will depend exclusively on the price of the commodities on the settlement dates specified by the derivative contracts.



	Fair Value of Derivative Contracts
	Commodity			Interest Rate			Total
	(In Thousands)
As of December 31, 2011	$	50,543		$	20,556		$	71,099
Net increase in fair value	36,977			3,767			40,744
Net contract gains realized	(78,637		)	(8,479		)	(87,116		)
As of September 30, 2012	$	8,883		$	15,844		$	24,727

Interest Rates on Borrowings

The following table presents principal amounts and related interest rates by year of maturity for Forest’s debt obligations at September 30, 2012.



	2013			2014⁽¹⁾			2019			2020			Total
	(Dollar Amounts in Thousands)
Senior notes:
Principal	$	12		$	600,000		$	1,000,000		$	500,000		$	2,100,012
Fixed interest rate	7.00		%	8.50		%	7.25		%	7.50		%	7.67		%
Effective interest rate⁽²⁾	7.49		%	9.47		%	7.24		%	7.50		%	7.94		%

____________________________________________


(1)	In September 2012, Forest irrevocably called $300 million (50% of the aggregate principal amount) of the 8½% senior notes due 2014 and redeemed those called notes in October 2012.


(2)	The effective interest rates on the senior notes differ from the fixed interest rates due to the amortization of related discounts or premiums on the notes.

Foreign Currency Exchange Risk

We conduct business in Italy and South Africa, and thus are subject to foreign currency exchange rate risk on cash flows related primarily to expenses and investing transactions. We have not entered into any foreign currency forward contracts

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or other similar financial instruments to manage this risk. Expenditures incurred relative to the foreign concessions held by us outside of North America have been primarily United States dollar-denominated.

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Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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, Patrick R. McDonald, 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, 2012 (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.

Changes in Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled, Forest Oil Corporation, et al. v. El Rucio Land & Cattle Company Inc., et al., which occurred in Harris County, Texas. The third member of the arbitration panel has dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration decision awards the claimant $23 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55^th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest is seeking to have this judgment reversed on appeal and believes it has meritorious arguments in support thereof.

In August 2007, Forest sold all of its Alaska assets to Pacific Energy Resources Ltd. and its related entities (“PERL”). On March 9, 2009, PERL filed for bankruptcy. As part of the plan of liquidation of its bankruptcy, PERL “abandoned” its interests in many of the Alaska assets sold to it by Forest, including the Trading Bay Unit and Trading Bay Field (“Trading Bay”). On December 2, 2010, Union Oil Company of California (“Unocal”) filed a lawsuit styled, Union Oil Company of California v. Forest Oil Corporation. In the lawsuit, the plaintiff complained about PERL’s abandonment of Trading Bay and asserted that PERL has failed to pay approximately $49 million in joint interest billings owed on those properties to date from the time PERL owned them. The plaintiff claimed that, as predecessor to PERL, Forest was liable for PERL’s share of all joint interest billings owed on Trading Bay. As of December 31, 2011, Unocal sold its interest in the Trading Bay assets, including its claims against Forest, to Hilcorp Alaska, LLC, and Hilcorp was substituted for Unocal as plaintiff in the lawsuit. In August 2012, Forest and the plaintiff reached a settlement whereby the plaintiff released Forest from all claims, agreed to indemnify Forest with respect to all decommissioning and abandonment liabilities associated with Trading Bay, and dismissed the complaint against Forest in exchange for a $7 million payment from Forest.

Except as described above and as disclosed in Part II, Item 1 of the Quarterly Reports on Form 10-Q for the quarter ended March 31, 2012, and June 30, 2012, respectively, there have been no material changes to the disclosure included in Part I, Item 3, of the Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

In addition to the proceedings described above, we are also a party to various other lawsuits, claims, and proceedings in the ordinary course of business. These proceedings are subject to uncertainties inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss associated with these proceedings would not be material to our consolidated financial position; however, in the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flow.

Item 1A. RISK FACTORS

The risks described under the caption “Risk Factors” in Item 8.01 of our Current Report on Form 8-K filed on September 12, 2012 (the “Form 8-K”), are incorporated herein by reference. There have been no material changes to the risks described in Item 8.01 of the Form 8-K.

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Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

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

Issuer Purchases of Equity Securities

The table below sets forth information regarding repurchases of our common stock during the third quarter 2012. 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. Forest does not consider this a share buyback program.



Period	Total # of Shares Purchased	Average Price Paid Per Share		Total # of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum # (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs
July 2012	8,333	$	6.83	—	—
August 2012	940	6.89		—	—
September 2012	178	8.04		—	—
Third Quarter Total	9,451	$	6.85	—	—

Table of Contents

Item 6. EXHIBITS



(a)			Exhibits.

1.1			Purchase Agreement, dated as of September 12, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and the Initial Purchasers named therein, incorporated by reference to Exhibit 1.1 to Form 8-K for Forest Oil Corporation filed September 17, 2012.

3.1			Restated Certificate of Incorporation of Forest Oil Corporation, as amended to date, incorporated herein by reference to Exhibit 3.2 to Form 8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001-13515).

3.2			Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, and No. 5, incorporated herein by reference to Exhibit 3.6 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2011 (File No. 001-13515).

4.1			Indenture, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and U.S. National Bank Association, incorporated by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation filed September 17, 2012 (File No. 001-13515).

4.2			Registration Rights Agreement, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and J.P. Morgan Securities LLC, as representative of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K for Forest Oil Corporation filed September 17, 2012 (File No. 001-13515).

10.1			Form of Restricted Stock Inducement Award Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.2			Form of CEO Plan Performance Unit Award Agreement, incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.3			Form of Performance Unit Inducement Award Agreement, incorporated by reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.4			Form of CEO Severance Agreement, incorporated by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.5			Form of CEO Plan Restricted Stock Award Agreement, incorporated by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.6			Agreement for Purchase and Sale of Assets, dated as of October 11, 2012, by and between Forest Oil Corporation and Texas Petroleum Investment Company, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001-13515).

31.1*			Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

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.

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.

____________________________________________


*	Filed herewith.

+ Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

++ The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

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SIGNATURES

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.



	FOREST OIL CORPORATION (Registrant)

October 29, 2012	By:	/s/ PATRICK R. MCDONALD
		Patrick R. McDonald Chief Executive Officer and Director (on behalf of the Registrant and as Principal Executive Officer)

	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)

Table of Contents

Exhibit Index



1.1			Purchase Agreement, dated as of September 12, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and the Initial Purchasers named therein, incorporated by reference to Exhibit 1.1 to Form 8-K for Forest Oil Corporation filed September 17, 2012.

3.1			Restated Certificate of Incorporation of Forest Oil Corporation, as amended to date, incorporated herein by reference to Exhibit 3.2 to Form 8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001-13515).

3.2			Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, and No. 5, incorporated herein by reference to Exhibit 3.6 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2011 (File No. 001-13515).

4.1			Indenture, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and U.S. National Bank Association, incorporated by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation filed September 17, 2012 (File No. 001-13515).

4.2			Registration Rights Agreement, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and J.P. Morgan Securities LLC, as representative of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Form 8-K for Forest Oil Corporation filed September 17, 2012 (File No. 001-13515).

10.1			Form of Restricted Stock Inducement Award Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.2			Form of CEO Plan Performance Unit Award Agreement, incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.3			Form of Performance Unit Inducement Award Agreement, incorporated by reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.4			Form of CEO Severance Agreement, incorporated by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.5			Form of CEO Plan Restricted Stock Award Agreement, incorporated by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.6			Agreement for Purchase and Sale of Assets, dated as of October 11, 2012, by and between Forest Oil Corporation and Texas Petroleum Investment Company, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001-13515).

31.1*			Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

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.

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.

____________________________________________


*	Filed herewith.

+ Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.