QuickLinks -- Click here to rapidly navigate through this document

---

---

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

---

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2007
Or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                             to

Commission File Number 1-13515

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

New York (State or other jurisdiction of incorporation or organization)	25-0484900 (I.R.S. Employer Identification No.)
707 17th Street, Suite 3600 Denver, Colorado 80202 (Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 812-1400

---

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

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer    ý

Accelerated filer    o

Non-accelerated filer    o

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

        As of October 31, 2007 there were 88,090,880 shares of the registrant's common stock, par value $.10 per share, outstanding.

---

---

---

FOREST OIL CORPORATION
INDEX TO FORM 10-Q
September 30, 2007

Part I—FINANCIAL INFORMATION
	Item 1—Financial Statements
		Condensed Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006		1
		Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2007 and 2006		2
		Condensed Consolidated Statement of Shareholders' Equity for the Nine Months Ended September 30, 2007		3
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006		4
		Notes to Condensed Consolidated Financial Statements		5
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations			32
	Item 3—Quantitative and Qualitative Disclosures About Market Risk			44
	Item 4—Controls and Procedures			47
Part II—OTHER INFORMATION
	Item 1—Legal Proceedings			48
	Item 1A—Risk Factors			48
	Item 6—Exhibits			50
Signatures				51

i

---

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)
(In Thousands, Except Share Data)

					September 30, 2007			December 31, 2006
ASSETS
Current assets:
	Cash and cash equivalents				$	8,814		33,164
	Accounts receivable					162,761		125,446
	Derivative instruments					36,142		53,205
	Other investments					41,408		—
	Other current assets					76,170		49,185
		Total current assets				325,295		261,000
Property and equipment, at cost:
	Oil and gas properties, full cost method of accounting:
		Proved, net of accumulated depletion of $2,620,554 and $2,265,018				4,133,119		2,486,153
		Unproved				677,734		261,259
			Net oil and gas properties			4,810,853		2,747,412
	Other property and equipment, net of accumulated depreciation and amortization of $28,267 and $32,504					35,864		42,514
			Net property and equipment			4,846,717		2,789,926
Derivative instruments						3,447		15,019
Goodwill						290,182		86,246
Other assets						50,789		36,881
					$	5,516,430		3,189,072
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable				$	348,027		224,933
	Accrued interest					36,370		6,235
	Derivative instruments					33,325		1,294
	Current portion of long-term debt					266,556		2,500
	Asset retirement obligations					1,151		2,694
	Deferred income taxes					—		14,907
	Other current liabilities					17,420		11,378
		Total current liabilities				702,849		263,941
Long-term debt						1,436,378		1,204,709
Asset retirement obligations						95,531		61,408
Derivative instruments						15,159		811
Deferred income taxes						813,291		191,957
Deferred gains						27,725		—
Other liabilities						52,221		32,240
	Total liabilities					3,143,154		1,755,066
Shareholders' equity:
	Preferred stock, none issued and outstanding					—		—
	Common stock, 88,051,324 and 62,998,155 shares issued and outstanding					8,805		6,300
	Capital surplus					1,958,060		1,215,660
	Retained earnings					278,433		137,796
	Accumulated other comprehensive income					127,978		74,250
	Total shareholders' equity					2,373,276		1,434,006
					$	5,516,430		3,189,072

See accompanying Notes to Condensed Consolidated Financial Statements.

1

---

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

					Three Months Ended September 30,					Nine Months Ended September 30,
					2007			2006		2007		2006
					(In Thousands, Except Per Share Amounts)
Revenue:
	Oil and gas sales:
		Natural gas			$	189,985		90,296		428,039		312,102
		Oil, condensate, and natural gas liquids				123,032		110,624		321,473		318,137
			Total oil and gas sales			313,017		200,920		749,512		630,239
	Marketing, processing, and other					8		1,919		791		5,899
			Total revenue			313,025		202,839		750,303		636,138
Operating expenses:
	Lease operating expenses					48,269		34,963		129,336		115,823
	Production and property taxes					16,112		8,974		36,830		30,699
	Transportation and processing costs					5,764		5,494		15,216		15,865
	General and administrative (including stock-based compensation)					16,716		10,548		43,094		38,755
	Depreciation and depletion					122,005		62,505		268,590		203,426
	Accretion of asset retirement obligations					1,980		1,226		4,547		5,879
	Impairments					—		—		—		2,078
	Gain on sale of assets					—		—		(7,176	)	—
	Spin-off costs					—		—		—		5,416
			Total operating expenses			210,846		123,710		490,437		417,941
Earnings from operations						102,179		79,129		259,866		218,197
Other income and expense:
	Interest expense					32,567		19,122		86,023		51,613
	Unrealized losses (gains) on derivative instruments, net					12,415		(77,914	)	35,440		(68,178	)
	Realized (gains) losses on derivative instruments, net					(30,387	)	12,883		(64,791	)	30,496
	Unrealized gain on other investments					(2,521	)	—		(2,521	)	—
	Unrealized foreign currency exchange (gains) losses					(1,075	)	766		(7,395	)	766
	Other expense (income), net					4,145		(950	)	4,379		(200	)
			Total other income and expense			15,144		(46,093	)	51,135		14,497
Earnings before income taxes and discontinued operations						87,035		125,222		208,731		203,700
Income tax expense:
	Current					3,320		(743	)	6,415		2,078
	Deferred					25,728		49,031		60,639		66,391
			Total income tax expense			29,048		48,288		67,054		68,469
Earnings from continuing operations						57,987		76,934		141,677		135,231
Income from discontinued operations, net of tax						—		—		—		2,422
Net earnings					$	57,987		76,934		141,677		137,653
Basic earnings per common share:
	Earnings from continuing operations				$	.67		1.24		1.96		2.17
	Income from discontinued operations, net of tax					—		—		—		.04
	Basic earnings per common share				$	.67		1.24		1.96		2.21
Diluted earnings per common share:
	Earnings from continuing operations				$	.65		1.21		1.91		2.13
	Income from discontinued operations, net of tax					—		—		—		.04
	Diluted earnings per common share				$	.65		1.21		1.91		2.17

See accompanying Notes to Condensed Consolidated Financial Statements.

2

---

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(Unaudited)

			Common Stock									Accumulated Other Comprehensive Income
								Capital Surplus		Retained Earnings				Total Shareholders' Equity
			Shares		Amount
			(In Thousands)
Balances at December 31, 2006			62,998		$	6,300		1,215,660		137,796		74,250		1,434,006
	Acquisition of Houston Exploration		23,990			2,399		724,013		—		—		726,412
	Tax benefit of stock options exercised		—			—		28		—		—		28
	Exercise of stock options		421			42		7,337		—		—		7,379
	Employee stock purchase plan		24			2		744		—		—		746
	Restricted stock issued, net of cancellations		618			62		(401	)	—		—		(339	)
	Amortization of stock-based compensation		—			—		10,679		—		—		10,679
	Adoption of FIN 48		—			—		—		(1,040	)	—		(1,040	)
Comprehensive earnings:
	Net earnings		—			—		—		141,677		—		141,677
	Increase in unfunded postretirement benefits, net of tax		—			—		—		—		(274	)	(274	)
	Foreign currency translation		—			—		—		—		54,002		54,002
	Total comprehensive earnings													195,405
Balances at September 30, 2007			88,051		$	8,805		1,958,060		278,433		127,978		2,373,276

See accompanying Notes to Condensed Consolidated Financial Statements.

3

---

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

				Nine Months Ended September 30,
				2007			2006
				(In Thousands)
Operating activities:
	Net earnings			$	141,677		137,653
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation and depletion			268,590		203,426
		Accretion of asset retirement obligations			4,547		5,879
		Stock-based compensation			7,484		11,384
		Impairments			—		2,078
		Unrealized losses (gains) on derivative instruments, net			35,440		(68,178	)
		Amortization of deferred derivative losses			—		15,204
		Unrealized foreign currency exchange (gains) losses			(7,395	)	766
		Gain on sale of assets			(7,176	)	—
		Unrealized gain on other investments			(2,521	)	—
		Deferred income tax expense			60,639		67,617
		Other, net			2,931		(2,565	)
	Changes in operating assets and liabilities, net of effects of acquisitions and divestitures:
		Accounts receivable			36,081		966
		Other current assets			(2,565	)	(23,330	)
		Accounts payable			(34,724	)	(1,131	)
		Accrued interest and other current liabilities			17,781		(3,153	)
Net cash provided by operating activities					520,789		346,616
Investing activities:
	Acquisition of Houston Exploration, net of cash acquired (Note 2)				(775,960	)	—
	Capital expenditures for property and equipment:
		Exploration, development, and other acquisition costs			(535,252	)	(741,495	)
		Other fixed assets			(23,847	)	(9,718	)
	Proceeds from sale of Alaska Assets (Note 2)				400,000		—
	Proceeds from sales of other assets				101,734		1,367
	Other, net				—		120
Net cash used in investing activities					(833,325	)	(749,726	)
Financing activities:
	Issuance of 71/4% senior notes, net of issuance costs				739,176		—
	Proceeds from bank borrowings				1,208,553		1,167,963
	Repayments of bank borrowings				(1,104,387	)	(778,924	)
	Repayments of bank debt assumed in acquisition				(176,885	)	—
	Repayments of term loans				(375,000	)	—
	Proceeds from Spin-off (Note 2)				—		21,670
	Proceeds from the exercise of options and from employee stock purchase plan				8,125		5,246
	Other, net				(13,054	)	(8,599	)
Net cash provided by financing activities					286,528		407,356
Effect of exchange rate changes on cash					1,658		(75	)
Net (decrease) increase in cash and cash equivalents					(24,350	)	4,171
Cash and cash equivalents at beginning of period					33,164		7,231
Cash and cash equivalents at end of period				$	8,814		11,402
Cash paid during the period for:
	Interest			$	63,924		42,819
	Income taxes				3,401		5,243

See accompanying Notes to Condensed Consolidated Financial Statements.

4

---

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) BASIS OF PRESENTATION

        The Condensed Consolidated Financial Statements included herein are unaudited and include the accounts of Forest Oil Corporation and its consolidated subsidiaries (collectively, "Forest" or the "Company"). In the opinion of management, all adjustments, consisting of normal recurring accruals, have been made which are necessary for a fair presentation of the financial position of Forest at September 30, 2007, the results of its operations for the three and nine months ended September 30, 2007 and 2006, and its cash flows for the nine months ended September 30, 2007 and 2006. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for liquids (oil, condensate, and natural gas liquids) and natural gas and other factors.

        In the course of preparing the Condensed Consolidated Financial Statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, 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 initially established.

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

        Certain amounts in the prior year financial statements have been reclassified to conform to the 2007 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, 2006, previously filed with the Securities and Exchange Commission.

(2) ACQUISITIONS AND DIVESTITURES

Acquisitions

Acquisition of Houston Exploration

        On June 6, 2007, Forest completed the acquisition of The Houston Exploration Company ("Houston Exploration") in a cash and stock transaction totaling $1.5 billion and the assumption of Houston Exploration's debt. Houston Exploration was an independent natural gas and oil producer engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. Houston Exploration had operations in four producing regions within the United States: South Texas, East Texas, the Arkoma Basin of Arkansas, and the Uinta and DJ Basins in the Rocky Mountains. The principal factors considered by management in making the acquisition included the mix of complementary high-quality assets in certain of the Company's existing core areas, lower-risk exploitation opportunities, expected increased cash flow from operations available for investing activities, and opportunities for cost savings through administrative and operational synergies. Pursuant to the terms and conditions of the agreement and plan of merger ("Merger Agreement"), Forest paid

5

---

total merger consideration of $750 million in cash and issued approximately 24 million common shares, valued at $30.28 per share. The per share value of the Forest common shares issued was calculated as the average of Forest's closing share price for a five day period surrounding the announcement date of the acquisition on January 7, 2007. The cash component of the merger consideration was financed from a private placement of $750 million of senior notes due 2019 and borrowings under the Company's $1.0 billion second amended and restated credit facilities that were executed on June 6, 2007. Immediately following the completion of the merger, Forest repaid all of Houston Exploration's outstanding bank debt totaling $177 million.

        The acquisition, which was accounted for using the purchase method of accounting, has been included in Forest's Condensed Consolidated Financial Statements since June 6, 2007, the date the acquisition closed. The following table represents the preliminary allocation of the total purchase price of Houston Exploration to the acquired assets and liabilities of Houston Exploration as of September 30, 2007. The allocation represents the estimated fair values assigned to each of the assets acquired and liabilities assumed. The purchase price allocation is preliminary, subject to the completion of evaluations of proved and unproved oil and gas properties, deferred income taxes, contractual arrangements and legal and environmental matters. These and other estimates are subject to change as additional information becomes available and is assessed by Forest.

6

---

        Goodwill of $201.4 million has been recognized to the extent that the consideration paid exceeded the fair value of the net assets acquired and has been assigned to the U.S. reporting unit. Goodwill is not expected to be deductible for tax purposes. The principal factors that contributed to the recognition of goodwill include the mix of complementary high-quality assets in certain of our existing core areas, lower-risk exploitation opportunities, expected increased cash flow from operations available for investing activities, and opportunities for cost savings through administrative and operational synergies.

        Included in the working capital assumed at the acquisition date was a severance accrual of $28.9 million for costs to involuntarily terminate employees of Houston Exploration. Management determined it would be necessary to eliminate certain overlapping positions to achieve cost savings through administrative and operational synergies. Management is still finalizing its business integration plans as a result of the acquisition and, accordingly, the severance accrual will be finalized once these plans are complete. The following table summarizes the activity in the severance accrual through September 30, 2007 since the acquisition date:

---

(1)

Represents cash severance and excise tax payments to involuntarily terminated employees of Houston Exploration as well as the related employer tax payments paid by the Company.

(2)

Represents the net adjustment made to the accrual as the Company continues to finalize the termination plan. This net adjustment was made to the cost of the acquired company.

        The remaining severance payments are expected to be made during the period October 2007 through February 2008.

        The following summary pro forma combined statement of operations data of Forest for the three and nine month periods ended September 30, 2007 and 2006 has been prepared to give effect to the merger as if the merger had occurred on January 1, 2007 and 2006, respectively. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2007 and 2006 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors. The pro forma financial information also gives pro forma effect to Forest's spin-off of its offshore Gulf of Mexico operations completed in March 2006 and Houston Exploration's sale of substantially all of its

7

---

offshore Gulf of Mexico operations completed in June 2006, as though each disposition occurred on January 1, 2006.

Cotton Valley Acquisition

        On March 31, 2006, Forest completed the acquisition of oil and gas properties located primarily in the Cotton Valley trend in East Texas for approximately $255 million, as adjusted to reflect an economic effective date of February 1, 2006. Forest funded this acquisition utilizing its bank credit facilities.

Divestitures

Sale of Alaska Assets

        On August 27, 2007, Forest sold substantially all of its Alaska assets (the "Alaska Assets") to Pacific Energy Resources Ltd. ("PERL"). The total consideration received for the Alaska Assets included $400 million in cash, 10 million restricted shares of PERL common stock, and a zero coupon senior subordinated note from PERL due 2014 in the principal amount at stated maturity of $60.8 million. A portion of the cash consideration, $269 million, was applied to prepay all amounts due under the Alaska Credit Agreements, including accrued interest and prepayment premiums. Consideration received by Forest in the form of the PERL common stock and the zero coupon senior subordinated note are being held in other investments within the Condensed Consolidated Balance Sheet. Forest accounts for these investments as trading securities in accordance with Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Investments in debt and equity securities classified as trading securities are recorded at fair value with unrealized gains and losses recognized in the Condensed Consolidated Statements of Operations.

Spin-off and Merger of Offshore Gulf of Mexico Operations

        On March 2, 2006, Forest completed the spin-off of its offshore Gulf of Mexico operations by means of a special dividend, which consisted of a pro rata spin-off (the "Spin-off") of all outstanding

8

---

shares of Forest Energy Resources, Inc. (hereinafter known as Mariner Energy Resources, Inc. or "MERI"), a total of approximately 50.6 million shares of common stock, to holders of record of Forest common stock as of the close of business on February 21, 2006. Immediately following the Spin-off, MERI was merged with a subsidiary of Mariner Energy, Inc. ("Mariner") (the "Merger"). Mariner's common stock commenced trading on the New York Stock Exchange on March 3, 2006.

        The Spin-off was a tax-free transaction for federal income tax purposes. Prior to the Merger, as part of the Spin-off, MERI paid Forest $176.1 million. The $176.1 million was drawn on a newly created bank credit facility established by MERI immediately prior to the Spin-off. This credit facility and associated liability were included in the Spin-off. Subsequent to the closing, Forest received additional net cash proceeds of $21.7 million from MERI for a total of $197.8 million. In accordance with the transaction agreements, Forest and MERI had submitted post-closing adjustments from which Forest paid MERI $5.8 million. Additional adjustments to the cash amount may occur pending the resolution of certain matters which have been submitted to binding arbitration.

        The table below sets forth the assets and liabilities included in the Spin-off (in thousands):

Sale of ProMark—Discontinued Operations

        On March 1, 2004, the Company sold the assets and business operations of Producers Marketing, Ltd. ("ProMark") to Cinergy Canada, Inc. ("Cinergy") for $11.2 million CDN. As a result of the sale, ProMark's results of operations were reported as discontinued operations in the historical financial statements. Under the terms of the purchase and sale agreement, Forest may receive additional contingent consideration over a period of five years through February 2009. During the nine months ended September 30, 2006, Forest recognized an additional $3.6 million contingent payment ($2.4 million net of tax), which has been reflected as income from discontinued operations in the Condensed Consolidated Statements of Operations. No contingent payments will be received during 2007.

Other Divestitures

        During the nine months ended September 30, 2007, Forest sold properties in addition to the Alaska Assets for total proceeds of $39.1 million, including overriding royalty interests in Australia for

9

---

net proceeds of $7.2 million that resulted in a gain on the sale of $7.2 million ($4.5 million net of tax). In addition, in August 2007, the Company entered into a sale-leaseback transaction whereby the Company sold its drilling rigs for cash proceeds of $62.6 million and simultaneously entered into an operating lease with the buyer which provides for monthly rental payments of $.9 million for a term of seven years. A deferred gain of $32.5 million resulted from the sale of the drilling rigs and will be amortized over the term of the lease.

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

Earnings per Share

        Basic earnings per share is computed by dividing net earnings attributable to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares.

        Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of stock options, unvested restricted stock grants, and unvested phantom stock units. The following sets forth the calculation of basic and diluted earnings per share:

			Three Months Ended September 30,					Nine Months Ended September 30,
			2007			2006		2007		2006
			(In Thousands, Except Per Share Amounts)
Earnings from continuing operations			$	57,987		76,934		141,677		135,231
Income from discontinued operations, net of tax				—		—		—		2,422
Net earnings			$	57,987		76,934		141,677		137,653
Weighted average common shares outstanding				86,802		62,250		72,434		62,187
Add dilutive effects of stock options, unvested restricted stock grants, and unvested phantom stock units				1,811		1,234		1,585		1,194
Weighted average common shares outstanding, including the effects of dilutive securities				88,613		63,484		74,019		63,381
Basic earnings per share:
	From continuing operations		$	.67		1.24		1.96		2.17
	From discontinued operations			—		—		—		.04
	Basic earnings per share		$	.67		1.24		1.96		2.21
Diluted earnings per share:
	From continuing operations		$	.65		1.21		1.91		2.13
	From discontinued operations			—		—		—		.04
	Diluted earnings per share		$	.65		1.21		1.91		2.17

10

---

Comprehensive Earnings (Loss)

        Comprehensive earnings (loss) is a term used to refer to net earnings plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net earnings. Items included in Forest's other comprehensive income (loss) for the three and nine months ended September 30, 2007 and 2006 are foreign currency gains (losses) related to the translation of the assets and liabilities of Forest's Canadian operations, changes in the unfunded postretirement benefits, and unrealized gains (losses) related to the changes in the fair value of derivative instruments designated as cash flow hedges.

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

11

---

(4) STOCK-BASED COMPENSATION

        The table below sets forth total stock-based compensation recorded during the three and nine months ended September 30, 2007 and 2006 under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123 (Revised), Share-Based Payment ("SFAS 123(R)").

			Stock Options			Restricted Stock		Phantom Stock Units		Total(1)
			(In Thousands)
Three months ended September 30, 2007:
	Total stock-based compensation costs		$	1,089		3,394		551		5,034
	Less: stock-based compensation costs capitalized			(501	)	(1,526	)	(350	)	(2,377	)
	Stock-based compensation costs expensed		$	588		1,868		201		2,657
Nine months ended September 30, 2007:
	Total stock-based compensation costs		$	3,771		6,658		1,343		11,772
	Less: stock-based compensation costs capitalized			(1,139	)	(2,546	)	(854	)	(4,539	)
	Stock-based compensation costs expensed		$	2,632		4,112		489		7,233
Unamortized stock-based compensation costs as of September 30, 2007			$	6,572		28,549		5,084	(2)	40,205
Weighted average amortization period remaining				1.9 years		2.0 years		2.1 years		2.0 years
Three months ended September 30, 2006:
	Total stock-based compensation costs		$	961		1,305		162		2,428
	Less: stock-based compensation costs capitalized			(425	)	(398	)	(96	)	(919	)
	Stock-based compensation costs expensed		$	536		907		66		1,509
Nine months ended September 30, 2006:
	Total stock-based compensation costs		$	3,983		12,827		1,682		18,492
	Less: stock-based compensation costs capitalized			(1,135	)	(4,684	)	(944	)	(6,763	)
	Stock-based compensation costs expensed		$	2,848		8,143		738		11,729

---

(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, 2007, respectively, under the provisions of SFAS 123(R). Compensation costs for the employee stock purchase plan during the three and nine month periods ended September 30, 2006 were $.1 million and $.2 million, respectively.

(2)

Based on the closing price of the Company's common stock on September 30, 2007.

12

---

Stock Options

        The following table summarizes stock option activity in the Company's stock-based compensation plans for the nine months ended September 30, 2007.

		Number of Shares		Weighted Average Exercise Price			Aggregate Intrinsic Value (In Thousands)(1)			Number of Shares Exercisable
Outstanding at January 1, 2007		3,328,279		$	18.80		$	46,279		2,338,751
Granted at fair value(2)		651,655			42.10
Exercised		(422,326	)		17.56			8,725
Cancelled		(388,082	)		40.05
Outstanding at September 30, 2007		3,169,526			21.15			69,834		2,303,952

---

(1)

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

(2)

During the second quarter, the Company granted 651,655 stock options, which includes 616,655 options granted to Houston Exploration employees pursuant to the Merger Agreement after closing of the acquisition on June 6, 2007. The value of these options will be amortized as compensation costs over the four year vesting period from the date of grant.

        The fair value of stock options granted during 2007 was estimated using the Black-Scholes option pricing model. The following weighted average assumptions were used to compute the fair market value of stock options granted during the nine months ended September 30, 2007:

        The expected life of the options is based, in part, on historical exercise patterns of the holders of options with similar terms, with consideration given to how historical patterns may differ from future exercise patterns based on current or expected market conditions and employee turnover. The risk free interest rate was based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility was based on the historical volatility of the Company's stock for a term consistent with the expected life of the options.

13

---

Restricted Stock and Phantom Stock Units

        The following table summarizes the restricted stock and phantom stock unit activity in the Company's stock-based compensation plans for the nine months ended September 30, 2007.

		Restricted Stock					Phantom Stock Units
		Number of Shares		Weighted Average Grant Date Fair Value			Number of Shares		Weighted Average Grant Date Fair Value
Unvested at January 1, 2007		627,450		$	43.15		77,950		$	44.32
Awarded		672,450			41.32		90,400			40.98
Vested		(25,150	)		29.33		—			—
Forfeited		(44,350	)		42.19		(3,850	)		43.71
Unvested at September 30, 2007		1,230,400			42.47		164,500			42.50

        The restricted stock and phantom stock units generally vest on the third anniversary of the date of the award, but may vest earlier upon a qualifying disability, death, retirement, or a change in control of the Company in accordance with the terms of the underlying agreement. The phantom stock units can be settled in cash, shares of common stock, or a combination of both. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements.

(5) DEBT

        Components of debt are as follows:

		September 30, 2007									December 31, 2006
		Principal			Unamortized Premium (Discount)		Other(3)		Total		Principal		Unamortized Premium (Discount)		Other(3)		Total
		(In Thousands)
U.S. Credit Facility		$	115,000		—		—		115,000		23,000		—		—		23,000
Canadian Credit Facility			111,577		—		—		111,577		84,094		—		—		84,094
Term Loan Agreements(1)			—		—		—		—		375,000		—		—		375,000
8% Senior Notes due 2008			265,000		(73	)	1,629		266,556		265,000		(146	)	3,346		268,200
8% Senior Notes due 2011			285,000		5,490		3,526		294,016		285,000		6,458		4,152		295,610
7% Senior Subordinated Notes due 2013(2)			5,822		(166	)	—		5,656		—		—		—		—
73/4% Senior Notes due 2014			150,000		(1,572	)	11,701		160,129		150,000		(1,751	)	13,056		161,305
71/4% Senior Notes due 2019(2)			750,000		—		—		750,000		—		—		—		—
Total debt			1,682,399		3,679		16,856		1,702,934		1,182,094		4,561		20,554		1,207,209
Less: current portion of long-term debt			(265,000	)	73		(1,629	)	(266,556	)	(2,500	)	—		—		(2,500	)
Long-term debt		$	1,417,399		3,752		15,227		1,436,378		1,179,594		4,561		20,554		1,204,709

---

(1)

On August 27, 2007, in connection with the sale of the Alaska Assets, Forest paid all outstanding amounts owed under its Term Loan Agreements.

14

---

(2)

In connection with the acquisition of Houston Exploration, Forest assumed approximately $5.8 million of 7% Senior Subordinated Notes due 2013 and issued $750 million of 7¹/4% Senior Notes due 2019 for net proceeds of approximately $739.2 million after deducting initial purchasers' discounts.

(3)

Represents the unamortized portion of gains realized upon termination of interest rate swaps that were accounted for as fair value hedges. The gains are being amortized as a reduction of interest expense over the terms of the notes.

Credit Facilities

        On June 6, 2007, Forest entered into amended and restated credit facilities totaling $1.0 billion. The amended and restated facilities consist of an $850 million U.S. credit facility (the "U.S. Facility") through a syndicate of banks led by JPMorgan Chase Bank, N.A. and a $150 million Canadian credit facility (the "Canadian Facility", and together with the U.S. Facility, the "Credit Facilities") through a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Credit Facilities mature in June 2012. Subject to the agreement of Forest and the applicable lenders, the size of the Credit Facilities may be increased by $800 million in the aggregate.

        Forest's availability under the Credit Facilities will be governed by a borrowing base ("Global Borrowing Base") which currently is set at $1.4 billion, with $1.25 billion allocated to the U.S. credit facility and $150 million allocated to the Canadian credit facility. The determination of the Global Borrowing Base is made by the lenders in their sole discretion taking into consideration the estimated value of Forest's oil and gas properties in accordance with the lenders' customary practices for oil and gas loans. The Global Borrowing Base is redetermined semi-annually and the available borrowing amount could be increased or decreased as a result of such redeterminations. In addition, Forest and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the Global Borrowing Base redetermined.

        The Credit Facilities include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and include financial covenants. Interest rates and collateral requirements under the Credit Facilities will vary based on Forest's credit ratings and financial condition, as governed by certain financial tests.

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

        The Credit Facilities are collateralized by Forest's assets. Forest is required to mortgage, and grant a security interest in, 75% of the present value of the proved oil and gas properties and related assets of Forest and its subsidiaries. If Forest's corporate credit ratings by Moody's and S&P meet pre-established levels, the security requirements would cease to apply and at Forest's request the banks would release their liens and security interest on Forest's properties.

15

---

        From time to time, Forest and the syndication agents, documentation agents, global administrative agent and the other lenders party to the Credit Facilities, engage in other transactions, including securities offerings where such parties or their affiliates, may serve as an underwriter or initial purchaser of Forest's securities and, or serve as counterparties to Forest's hedging arrangements.

Term Loan Agreements

        On December 8, 2006, Forest, through its wholly-owned subsidiaries Forest Alaska Operating LLC and Forest Alaska Holding LLC (together "Forest Alaska"), issued, on a non-recourse basis to Forest, term loan financing facilities in the aggregate principal amount of $375 million. The issuance was comprised of two term loan facilities, including a $250 million first lien credit agreement and a $125 million second lien credit agreement (together the "Credit Agreements"). The loan proceeds were used to fund a $350 million distribution to Forest, which Forest used to pay down its U.S. credit facility, and to provide Forest Alaska working capital for its operations and pay transaction fees and expenses.

        During the nine months ended September 30, 2007, Forest made scheduled prepayments of $1.3 million and a voluntary repayment of $110.0 million on the first lien credit agreement. In conjunction with the sale of the Alaska Assets on August 27, 2007, Forest used a portion of the $400 million cash consideration to repay in full the remaining $263.8 million principal balance outstanding under the first and second lien facilities.

7¹/4% Senior Notes Due 2019

        On June 6, 2007 Forest issued $750 million of 7¹/4% senior notes due in 2019 ("the 7¹/4% Notes") at par for net proceeds of approximately $739.2 million, after deducting initial purchaser discounts, which were used to fund a portion of the cash merger consideration for Forest's acquisition of Houston Exploration. The 7¹/4% Notes were issued under an indenture (the "Indenture") dated as of June 6, 2007 among Forest, Forest Oil Permian Corporation, a wholly-owned subsidiary of Forest ("Forest Permian"), as subsidiary guarantor, and U.S. Bank National Association, as trustee. The 7¹/4% Notes are jointly and severally guaranteed by Forest Permian on an unsecured basis. Interest is payable on June 15 and December 15 of each year, beginning December 15, 2007. The 7¹/4% Notes will mature on June 15, 2019.

        Forest may redeem up to 35% of the 7¹/4% Notes at any time prior to June 15, 2010, on one or more occasions, with the proceeds from certain equity offerings at a redemption price equal to 107.25% of the principal amount, plus accrued but unpaid interest. Forest may redeem the 7¹/4% Notes at any time beginning on or after June 15, 2012 at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued but unpaid interest:

16

---

        Forest may also redeem the 7¹/4% Notes, in whole or in part, at a price equal to the principal amount plus a "make whole" premium, at any time prior to June 15, 2012, using a discount rate of the Treasury rate plus 0.50%, plus accrued but unpaid interest.

        Forest and its restricted subsidiaries are subject to certain negative covenants under the Indenture governing the 7¹/4% Notes. The Indenture limits the ability of Forest and each of its restricted subsidiaries to, among other things: incur additional indebtedness, create certain liens, make certain types of "restricted payments", make investments, sell assets, enter into agreements that restrict dividends or other payments from its subsidiaries to itself, consolidate, merge or transfer all or substantially all of its assets, engage in transactions with affiliates, and pay dividends or make other distributions on capital stock or subordinated indebtedness.

7% Senior Subordinated Notes Due 2013

        In connection with the acquisition of Houston Exploration, Forest assumed $5.8 million of 7% senior subordinated notes due in 2013 ("the 7% Notes") originally issued by Houston Exploration in June 2003. The 7% Notes can be redeemed at the option of Forest, in whole or in part, at any time after June 15, 2008 at a price equal to 100% of the principal amount plus accrued but unpaid interest, if any, plus a specified premium that decreases yearly from 3.5% in 2008 to 0% in 2011 and thereafter. The 7% Notes are general unsecured obligations of Forest and rank subordinate in right of payment to all existing senior debt and will rank senior or equal in right to all of our existing and future subordinated debt. Interest is payable on June 15 and December 15 of each year.

(6) PROPERTY AND EQUIPMENT

        Forest uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which Forest has operations. During the periods presented, Forest's primary oil and gas operations were conducted in the United States and Canada. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Forest capitalized $12.7 million and $6.6 million of general and administrative costs (including stock-based compensation) during the three months ended September 30, 2007 and 2006, respectively. During the nine months ended September 30, 2007 and 2006, Forest capitalized $29.8 million and $24.1 million, respectively, of general and administrative costs (including stock-based compensation). Interest costs related to significant unproved properties that are under development are also capitalized to oil and gas properties. Forest capitalized interest expense attributed to unproved properties of $6.3 million and $.4 million during the three months ended September 30, 2007 and 2006, respectively. During the nine months ended September 30, 2007 and 2006, Forest capitalized $8.5 million and $2.4 million, respectively, of interest expense attributed to unproved properties.

        Investments in unproved properties, including related capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the

17

---

properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate. During the second quarter of 2006, the Company recorded an impairment of $2.1 million related to certain properties located in Gabon. The Gabon impairment was related to historical costs impaired to reflect a drilled dry hole.

        Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within each separate cost center. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs. There were no ceiling test impairments of oil and gas properties in 2007 or 2006, although the Company's ceiling test in each of its cost centers could be adversely impacted by declines in commodity prices.

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

        Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. Furniture and fixtures, computer hardware and software, and other equipment are depreciated on the straight-line or declining balance method, based upon estimated useful lives of the assets ranging from three to 15 years.

(7) ASSET RETIREMENT OBLIGATIONS

        Forest records estimated future asset retirement obligations pursuant to the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period to its present value. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Forest's asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

18

---

        The following table summarizes the activity for Forest's asset retirement obligations for the nine months ended September 30, 2007 and 2006:

(8) EMPLOYEE BENEFITS

        The following table sets forth the components of the net periodic cost of Forest's defined benefit pension plans (for which benefits have been frozen) and postretirement benefits in the United States for the three and nine months ended September 30, 2007 and 2006:

		Three Months Ended September 30,									Nine Months Ended September 30,
		Pension Benefits					Postretirement Benefits				Pension Benefits				Postretirement Benefits
		2007			2006		2007		2006		2007		2006		2007		2006
		(In Thousands)
Service cost		$	170		—		103		137		227		—		308		443
Interest cost			636		548		94		101		1,770		1,644		282		320
Curtailment gain(1)			—		—		—		—		—		—		—		(1,851	)
Expected return on plan assets			(641	)	(607	)	—		—		(1,922	)	(1,823	)	—		—
Amortization of prior service cost			79		—		—		—		105		—		—		—
Recognized actuarial loss (gain)			199		227		(22	)	—		589		682		(65	)	—
Total net periodic expense		$	443		168		175		238		769		503		525		(1,088	)

---

(1)

Forest recognized a $1.9 million curtailment gain in connection with the Spin-off on March 2, 2006. This gain was recorded as a reduction in general and administrative expense for the nine months ended September 30, 2006.

        Forest assumed a postretirement benefit obligation of approximately $5 million related to Houston Exploration's Supplemental Executive Retirement Plans ("SERPs") in the acquisition completed on

19

---

June 6, 2007. The SERPs are unfunded, non-tax qualified defined benefit pension plans, which provided retirement benefits to certain management level and other highly compensated employees. Participants in the SERPs are entitled to a monthly retirement benefit for life. As defined in the SERPs, all benefits under the plans become fully vested upon a change of control whether or not a participant's employment is terminated. The benefit payable is to be paid as a lump sum in the event of a change of control and the participant's employment is terminated without cause or if the participant resigns for good reason within two years following a change of control.

(9) DERIVATIVE INSTRUMENTS

        Forest periodically enters into derivative instruments such as swap, basis swap, and collar agreements in order to provide a measure of stability to Forest's cash flows in an environment of volatile oil and gas prices 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, various circumstances can cause commodity hedges to not qualify for cash flow hedge accounting either at the inception of the hedge or during the term of the hedge. When the criteria for cash flow hedge accounting are not met or when cash flow hedging is not elected, realized gains and losses (i.e., cash settlements) are recorded in other income and expense in the Condensed Consolidated Statements of Operations. Similarly, changes in the fair value of the derivative instruments are recorded as unrealized gains or losses in the Condensed Consolidated Statements of Operations. In contrast, cash settlements for derivative instruments that qualify for hedge accounting are recorded as additions to or reductions of oil and gas revenues while changes in fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. In March 2006, Forest elected to discontinue cash flow hedge accounting prospectively for all of its commodity derivative instruments. Accordingly, subsequent to March 2006, Forest has recognized all mark-to-market gains and losses in earnings, rather than deferring such amounts in accumulated other comprehensive income included in shareholders' equity.

20

---

        The table below summarizes the realized and unrealized gains and losses Forest incurred related to its oil and gas derivative instruments for the periods indicated.

		Three Months Ended September 30,					Nine Months Ended September 30,
		2007			2006		2007		2006
		(In Thousands)
Realized losses on derivatives designated as cash flow hedges(1)		$	—		2,250		—		40,607
Realized (gains) losses on derivatives not designated as cash flow hedges(2)			(30,178	)	12,883		(64,452	)	30,496
Ineffectiveness recognized on derivatives designated as cash flow hedges(2)			—		—		—		(5,573	)
Unrealized losses (gains) on derivatives not designated as cash flow hedges(2)			9,180		(77,914	)	33,995		(62,605	)
Total realized and unrealized (gains) losses recorded		$	(20,998	)	(62,781	)	(30,457	)	2,925

---

(1)

Included in oil and gas sales in the Condensed Consolidated Statements of Operations. Realized gains or losses on derivatives that had previously been designated as cash flow hedges at the time the Company elected to discontinue hedge accounting were required to be included as part of oil and gas sales.

(2)

Included in other income and expense in the Condensed Consolidated Statements of Operations.

21

---

        The tables below set forth Forest's outstanding commodity swaps and collars as of September 30, 2007:

---

(1)

Included in Forest's outstanding natural gas costless collars at September 30, 2007 are natural gas costless collars assumed in the Houston Exploration acquisition with a fair value of $(10.8) million. At September 30, 2007, these costless collars had weighted average hedged floor and ceiling prices per MMBtu of $7.00/8.49 for 110 Bbtu per day for the fourth quarter 2007, $7.20/8.51 for 100 Bbtu per day for January – February 2008, and $5.00/5.72 for 20 Bbtu per day for March – December 2008.

22

---

        Forest also uses basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX price and the index price at which the natural gas production is sold. The table below sets forth Forest's outstanding basis swaps as of September 30, 2007:

---

(1)

Included in Forest's outstanding basis swaps at September 30, 2007 are basis swaps assumed in the Houston Exploration acquisition with a fair value of $1.3 million. At September 30, 2007, these basis swaps are for 80 Bbtu per day for the fourth quarter 2007 and January – February 2008.

        At September 30, 2007, the fair values of Forest's commodity derivative contracts are presented within the Condensed Consolidated Balance Sheet as liabilities of $47.1 million (of which $32.7 million was classified as current) and assets of $39.6 million (of which $36.1 million was classified as current). Forest is exposed to risks associated with swap and collar agreements arising from movements in the prices of oil and natural gas and from the unlikely event of non-performance by the counterparties to the swap and collar agreements.

        In October 2007, Forest entered into four additional natural gas swap agreements covering 40 Bbtu per day for calendar 2008 at a weighted average hedged price per MMBtu of $8.20 with 10 Bbtu per day subject to a $6.00 written put. In November 2007, Forest entered into a natural gas costless collar agreement covering 10 Bbtu per day for the period March – December 2008 at hedged floor and ceiling prices per MMBtu of $8.00 and $9.00, respectively.

Interest Rate Swaps

        The Company also may enter into interest rate swap agreements in an attempt to normalize the mix of fixed and floating interest rates within its debt portfolio. Unrealized gains, losses, or any settlements are recorded in other income and expense in the Condensed Consolidated Statement of Operations. Pursuant to the requirements under Forest Alaska's Credit Agreements, Forest Alaska entered into two floating to fixed interest rate swaps. In March 2007, Forest Alaska entered into a $75 million floating to fixed interest rate swap for three years at a one month LIBOR fixed rate of 4.80%. In April 2007, Forest Alaska entered into a $112.5 million floating to fixed interest rate swap for three years at a one month LIBOR fixed rate of 4.96%. In August 2007, Forest Alaska novated these interest rate swaps to Forest. The Company has maintained these interest rate swaps to fix a portion of its variable rate interest on its Credit Facility borrowings which are LIBOR based. At September 30, 2007, the fair value of the interest rate swaps was a liability of $1.4 million (of which $.6 million was classified as current). For the three and nine months ended September 30, 2007, the Company recorded unrealized losses related to the interest rate swaps of $3.2 million and $1.4 million, respectively. For the three and nine months ended September 30, 2007, the Company recorded realized gains related to the interest rate swaps of $.2 million and $.3 million, respectively.

23

---

(10) GEOGRAPHICAL SEGMENTS

        Segment information has been prepared in accordance with Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information. Forest conducts operations in one industry segment, that being the oil and gas exploration and production industry, and has three reportable geographical business segments: United States, Canada, and International. Forest's remaining activities are not significant and therefore are not reported as a separate segment, but are included as a reconciling item in the information below. The segments were determined based upon the geographical location of operations in each business segment. The segment data presented below was prepared on the same basis as the Condensed Consolidated Financial Statements.

			Oil and Gas Operations
			Three Months Ended September 30, 2007									Nine Months Ended September 30, 2007
			United States			Canada		International		Total Company		United States		Canada		International		Total Company
			(In Thousands)
Revenue			$	269,683		43,334		—		313,017		609,060		140,452		—		749,512
Expenses:
	Lease operating expenses			40,705		7,564		—		48,269		106,151		23,185		—		129,336
	Production and property taxes			15,336		776		—		16,112		34,619		2,211		—		36,830
	Transportation and processing costs			3,187		2,577		—		5,764		7,298		7,918		—		15,216
	Depletion			99,893		20,578		—		120,471		204,133		61,065		—		265,198
	Accretion of asset retirement obligations			1,650		316		14		1,980		3,678		831		38		4,547
Earnings (loss) from operations			$	108,912		11,523		(14	)	120,421		253,181		45,242		(38	)	298,385
Capital expenditures			$	250,081		46,782		9,092		305,955		2,530,763		127,514		11,922		2,670,199
Goodwill			$	272,764		17,418		—		290,182		272,764		17,418		—		290,182

24

---

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

		Three Months Ended September 30, 2007			Nine Months Ended September 30, 2007
		(In Thousands)
Earnings from operations for reportable segments		$	120,421		298,385
Marketing, processing, and other			8		791
General and administrative expense (including stock-based compensation)			(16,716	)	(43,094	)
Administrative asset depreciation			(1,534	)	(3,392	)
Interest expense			(32,567	)	(86,023	)
Unrealized losses on derivative instruments, net			(12,415	)	(35,440	)
Realized gains on derivative instruments, net			30,387		64,791
Unrealized gain on other investments			2,521		2,521
Unrealized foreign currency exchange gains			1,075		7,395
Gain on sale of assets			—		7,176
Other expense, net			(4,145	)	(4,379	)
Earnings before income taxes and discontinued operations		$	87,035		208,731

			Oil and Gas Operations
			Three Months Ended September 30, 2006									Nine Months Ended September 30, 2006
			United States			Canada		International		Total Company		United States		Canada		International		Total Company
			(In Thousands)
Revenue			$	157,452		43,468		—		200,920		498,187		132,052		—		630,239
Expenses:
	Lease operating expenses			27,237		7,726		—		34,963		94,420		21,403		—		115,823
	Production and property taxes			8,248		726		—		8,974		28,520		2,179		—		30,699
	Transportation and processing costs			2,624		2,870		—		5,494		8,908		6,957		—		15,865
	Depletion			43,884		17,750		—		61,634		144,650		56,237		—		200,887
	Accretion of asset retirement obligations			951		263		12		1,226		5,069		776		34		5,879
Impairments				—		—		—		—		—		—		2,078		2,078
Earnings (loss) from operations			$	74,508		14,133		(12	)	88,629		216,620		44,500		(2,112	)	259,008
Capital expenditures			$	143,194		43,471		774		187,439		676,032		118,286		6,337		800,655
Goodwill			$	71,377		15,503		—		86,880		71,377		15,503		—		86,880

25

---

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

		Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
		(In Thousands)
Earnings from operations for reportable segments		$	88,629		259,008
Marketing, processing, and other			1,919		5,899
General and administrative expense (including stock-based compensation)			(10,548	)	(38,755	)
Administrative asset depreciation			(871	)	(2,539	)
Spin-off costs			—		(5,416	)
Interest expense			(19,122	)	(51,613	)
Unrealized gains on derivative instruments, net			77,914		68,178
Realized losses on derivative instruments, net			(12,883	)	(30,496	)
Unrealized foreign currency exchange loss			(766	)	(766	)
Other income, net			950		200
Earnings before income taxes and discontinued operations		$	125,222		203,700

(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

        Each of the Company's 8% Senior Notes due 2008, 8% Senior Notes due 2011, 7³/4% Senior Notes due 2014, and 7¹/4% Senior Notes due 2019 are fully and unconditionally guaranteed by a wholly-owned subsidiary of the Company (the "Guarantor Subsidiary"). The Company's remaining subsidiaries (the "Non-Guarantor Subsidiaries") have not provided guarantees. Based on this distinction, the following presents condensed consolidating financial information as of September 30, 2007 and December 31, 2006 and for the three and nine months ended September 30, 2007 and 2006 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiary, eliminating entries, and consolidated basis. Elimination entries presented are necessary to combine the entities.

26

---

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

(In Thousands)

						September 30, 2007											December 31, 2006
						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					$	2,690		35		6,089		—		8,814		771		126		32,267		—		33,164
	Accounts receivable						90,560		9,927		71,894		(9,620	)	162,761		48,010		9,428		69,709		(1,701	)	125,446
	Other current assets						141,459		499		11,762		—		153,720		82,227		2,380		17,783		—		102,390
				Total current assets			234,709		10,461		89,745		(9,620	)	325,295		131,008		11,934		119,759		(1,701	)	261,000
Property and equipment, at cost							5,170,905		232,091		2,092,542		—		7,495,538		2,819,163		236,143		2,032,142		—		5,087,448
	Less accumulated depreciation, depletion and amortization						1,771,079		77,316		800,426		—		2,648,821		1,605,072		63,624		628,826		—		2,297,522
				Net property and equipment			3,399,826		154,775		1,292,116		—		4,846,717		1,214,091		172,519		1,403,316		—		2,789,926
Investment in subsidiaries							716,096		—		—		(716,096	)	—		648,250		—		—		(648,250	)	—
Note receivable from subsidiary							73,307		—		—		(73,307	)	—		59,497		—		—		(59,497	)	—
Goodwill							249,804		—		40,378		—		290,182		48,417		—		37,829		—		86,246
Due from (to) parent and subsidiaries							263,042		25,145		(288,187	)	—		—		236,075		(16,276	)	(219,799	)	—		—
Other assets							50,738		1		3,497		—		54,236		43,256		1		8,643		—		51,900
						$	4,987,522		190,382		1,137,549		(799,023	)	5,516,430		2,380,594		168,178		1,349,748		(709,448	)	3,189,072
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable					$	274,593		10,690		72,364		(9,620	)	348,027		147,397		8,394		70,843		(1,701	)	224,933
	Current portion of long-term debt						266,556		—		—		—		266,556		—		—		2,500		—		2,500
	Other current liabilities						78,704		1,030		8,532		—		88,266		33,978		(2,111	)	4,641		—		36,508
				Total current liabilities			619,853		11,720		80,896		(9,620	)	702,849		181,375		6,283		77,984		(1,701	)	263,941
Long-term debt							1,324,801		—		111,577		—		1,436,378		748,115		—		456,594		—		1,204,709
Notes payable to parent							—		—		73,307		(73,307	)	—		—		—		59,497		(59,497	)	—
Other liabilities							138,802		1,870		49,964		—		190,636		57,496		1,831		35,132		—		94,459
Deferred income taxes							530,790		59,830		222,671		—		813,291		(40,398	)	40,949		191,406		—		191,957
				Total liabilities			2,614,246		73,420		538,415		(82,927	)	3,143,154		946,588		49,063		820,613		(61,198	)	1,755,066
Shareholders' equity							2,373,276		116,962		599,134		(716,096	)	2,373,276		1,434,006		119,115		529,135		(648,250	)	1,434,006
						$	4,987,522		190,382		1,137,549		(799,023	)	5,516,430		2,380,594		168,178		1,349,748		(709,448	)	3,189,072

27

---

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands)

					Three Months Ended September 30,
					2007											2006
					Parent Company			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated		Parent Company		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue:
		Natural gas			$	141,044		2,814		46,127		—		189,985		46,159		3,793		40,344		—		90,296
		Oil, condensate, and natural gas liquids				68,423		15,841		38,768		—		123,032		80,076		14,870		15,678		—		110,624
		Marketing, processing, and other				(328	)	—		996		(660	)	8		563		(7	)	2,519		(1,156	)	1,919
			Total revenue			209,139		18,655		85,891		(660	)	313,025		126,798		18,656		58,541		(1,156	)	202,839
Operating expenses:
	Lease operating expenses					25,838		4,151		18,271		9		48,269		24,043		3,958		6,964		(2	)	34,963
	Other direct operating costs					15,331		1,358		5,187		—		21,876		10,886		1,454		2,128		—		14,468
	General and administrative (including stock-based compensation)					13,466		32		3,218		—		16,716		8,910		54		1,584		—		10,548
	Depreciation and depletion					81,998		4,866		35,144		(3	)	122,005		35,378		4,711		22,416		—		62,505
	Other operating expenses					1,297		43		640		—		1,980		905		32		289		—		1,226
			Total operating expenses			137,930		10,450		62,460		6		210,846		80,122		10,209		33,381		(2	)	123,710
Earnings from operations						71,209		8,205		23,431		(666	)	102,179		46,676		8,447		25,160		(1,154	)	79,129
Equity earnings in subsidiaries						(52,430	)	—		—		52,430		—		20,993		—		—		(20,993	)	—
Other income and expense:
	Interest expense					25,341		—		11,818		(4,592	)	32,567		17,038		—		4,555		(2,471	)	19,122
	Unrealized losses (gains) on derivative instruments, net					7,000		1,126		4,289		—		12,415		(65,386	)	(16,167	)	3,639		—		(77,914	)
	Realized (gains) losses on derivative instruments, net					(28,441	)	(336	)	(1,610	)	—		(30,387	)	11,538		2,541		(1,196	)	—		12,883
	Unrealized gains on other investments					(2,521	)	—		—		—		(2,521	)	—		—		—		—		—
	Other (income) expense, net					(67,115	)	215		1,989		67,981		3,070		(3,512	)	7		144		3,177		(184	)
		Total other income and expense				(65,736	)	1,005		16,486		63,389		15,144		(40,322	)	(13,619	)	7,142		706		(46,093	)
Earnings before income taxes						84,515		7,200		6,945		(11,625	)	87,035		107,991		22,066		18,018		(22,853	)	125,222
		Income tax expense:				26,528		2,624		(104	)	—		29,048		31,057		8,574		8,657		—		48,288
Net earnings					$	57,987		4,576		7,049		(11,625	)	57,987		76,934		13,492		9,361		(22,853	)	76,934

28

---

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands)

					Nine Months Ended September 30,
					2007											2006
					Parent Company			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated		Parent Company		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue:
		Natural gas			$	266,253		9,810		151,976		—		428,039		171,995		11,782		128,325		—		312,102
		Oil, condensate, and natural gas liquids				156,227		40,696		124,550		—		321,473		212,683		40,961		64,493		—		318,137
		Marketing, processing, and other				(427	)	(1	)	4,069		(2,850	)	791		1,298		42		6,977		(2,418	)	5,899
			Total revenue			422,053		50,505		280,595		(2,850	)	750,303		385,976		52,785		199,795		(2,418	)	636,138
Operating expenses:
	Lease operating expenses					55,317		12,251		61,801		(33	)	129,336		81,401		10,879		23,659		(116	)	115,823
	Other direct operating costs					33,806		4,065		14,175		—		52,046		30,248		5,082		11,234		—		46,564
	General and administrative (including stock-based compensation)					33,706		100		9,288		—		43,094		33,207		164		5,384		—		38,755
	Depreciation and depletion					148,116		13,760		106,722		(8	)	268,590		111,974		14,488		76,964		—		203,426
	Gain on sale of assets					—		—		(7,176	)	—		(7,176	)	—		—		—		—		—
	Other operating expenses					2,438		153		1,956		—		4,547		10,278		93		3,002		—		13,373
			Total operating expenses			273,383		30,329		186,766		(41	)	490,437		267,108		30,706		120,243		(116	)	417,941
Earnings from operations						148,670		20,176		93,829		(2,809	)	259,866		118,868		22,079		79,552		(2,302	)	218,197
Equity earnings in subsidiaries						(20,524	)	—		—		20,524		—		70,794		—		—		(70,794	)	—
Other income and expense:
	Interest expense					54,064		9		43,716		(11,766	)	86,023		46,078		90		11,905		(6,460	)	51,613
	Unrealized losses (gains) on derivative instruments, net					5,099		6,995		23,346		—		35,440		(57,353	)	(16,627	)	5,802		—		(68,178	)
	Realized (gains) losses on derivative instruments, net					(50,393	)	(5,341	)	(9,057	)	—		(64,791	)	25,267		5,609		(380	)	—		30,496
	Unrealized gains on other investments					(2,521	)	—		—		—		(2,521	)	—		—		—		—		—
	Other (income) expense, net					(74,399	)	459		(4,254	)	75,178		(3,016	)	(6,365	)	(179	)	(2,896	)	10,006		566
			Total other income and expense			(68,150	)	2,122		53,751		63,412		51,135		7,627		(11,107	)	14,431		3,546		14,497
Earnings before income taxes and discontinued operations						196,296		18,054		40,078		(45,697	)	208,731		182,035		33,186		65,121		(76,642	)	203,700
			Income tax expense:			54,619		6,548		5,887		—		67,054		44,382		12,959		11,128		—		68,469
Earnings from continuing operations						141,677		11,506		34,191		(45,697	)	141,677		137,653		20,227		53,993		(76,642	)	135,231
Income from discontinued operations, net of tax						—		—		—		—		—		—		—		2,422		—		2,422
Net earnings					$	141,677		11,506		34,191		(45,697	)	141,677		137,653		20,227		56,415		(76,642	)	137,653

29

---

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)

				Nine Months Ended September 30,
				2007									2006
				Parent Company			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidated		Parent Company		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidated
Operating activities:
	Net earnings			$	95,980		11,506		34,191		141,677		61,011		20,227		56,415		137,653
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation and depletion			148,116		13,760		106,714		268,590		111,974		14,488		76,964		203,426
		Unrealized losses (gains) on derivative instruments, net			5,099		6,995		23,346		35,440		(57,353	)	(16,627	)	5,802		(68,178	)
		Deferred income tax expense			50,894		6,548		3,197		60,639		41,968		12,959		12,690		67,617
		Other, net			3,510		153		(5,793	)	(2,130	)	28,484		92		4,170		32,746
	Changes in operating assets and liabilities, net of effects of acquisitions and divestitures:
		Accounts receivable			23,835		(499	)	12,745		36,081		553		(402	)	815		966
		Other current assets			(12,275	)	1,881		7,829		(2,565	)	(21,409	)	(2,116	)	195		(23,330	)
		Accounts payable			(15,638	)	564		(19,650	)	(34,724	)	(5,368	)	(1,033	)	5,270		(1,131	)
		Accrued interest and other current liabilities			26,384		(179	)	(8,424	)	17,781		4,808		1,718		(9,679	)	(3,153	)
Net cash provided by operating activities					325,905		40,729		154,155		520,789		164,668		29,306		152,642		346,616
Investing activities:
	Acquisitions, net of cash acquired				(775,960	)	—		—		(775,960	)	—		—		—		—
	Capital expenditures for property and equipment				(619,509	)	(19,033	)	79,443		(559,099	)	(580,105	)	(25,964	)	(145,144	)	(751,213	)
	Proceeds from sale of Alaska				400,000		—		—		400,000
	Other, net				4,301		26,120		71,313		101,734		243		—		1,244		1,487
Net cash (used) provided by investing activities					(991,168	)	7,087		150,756		(833,325	)	(579,862	)	(25,964	)	(143,900	)	(749,726	)
Financing activities:
	Proceeds from bank borrowings				1,043,000		—		165,553		1,208,553		1,046,102		—		121,861		1,167,963
	Repayments of bank borrowings				(951,000	)	—		(153,387	)	(1,104,387	)	(687,000	)	—		(91,924	)	(778,924	)
	Repayments of debt				(176,885	)	—		(375,000	)	(551,885	)	—		—		—		—
	Issuance of 71/4% senior notes, net of issuance costs				739,176		—		—		739,176		—		—		—		—
	Net activity in investments of subsidiaries				11,356		(47,991	)	36,635		—		27,705		(3,229	)	(24,476	)	—
	Other, net				1,535		84		(6,548	)	(4,929	)	26,843		—		(8,526	)	18,317
Net cash provided (used) by financing activities					667,182		(47,907	)	(332,747	)	286,528		413,650		(3,229	)	(3,065	)	407,356
Effect of exchange rate changes on cash					—		—		1,658		1,658		—		—		(75	)	(75	)
Net increase (decrease) in cash and cash equivalents					1,919		(91	)	(26,178	)	(24,350	)	(1,544	)	113		5,602		4,171
Cash and cash equivalents at beginning of period					771		126		32,267		33,164		2,076		(114	)	5,269		7,231
Cash and cash equivalents at end of period				$	2,690		35		6,089		8,814		532		(1	)	10,871		11,402

30

---

(12) RECENT ACCOUNTING PRONOUNCEMENTS

        In June 2006, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 48, "Accounting for Uncertainty in Income Taxes," an interpretation of FAS 109, "Accounting for Income Taxes" ("FIN 48"), to create a single model to address accounting for uncertainty in income tax positions. FIN 48 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

        The Company adopted FIN 48 on January 1, 2007. As a result of the implementation of FIN 48 the Company recognized a liability for uncertain tax benefits of approximately $1.0 million which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The adoption of FIN 48 increased the Company's previously recognized liability for uncertain tax benefits of $.5 million to $1.5 million. The $1.5 million liability does not relate to uncertainties about the timing of items of income or deduction and would affect the Company's effective tax rate if recognized in the Company's income tax provision. The Company records interest accrued related to unrecognized tax benefits in interest expense and penalties in other expense, to the extent they apply. The Company recognized no significant interest or penalties at the date of its adoption of FIN 48.

        There was no change in the amount of unrecognized tax benefits during the nine months ended September 30, 2007. Furthermore, the Company does not expect any significant change in the total amounts of unrecognized tax benefits within the 12 months ending September 30, 2008.

        The statute of limitations is closed for the Company's U.S. federal income tax returns for years ending before and including December 31, 2002. Pre-acquisition returns of acquired businesses are also closed for tax years ending before and including December 31, 2002. However, the Company has utilized, and will continue to utilize, net operating losses ("NOLs") (including NOLs of acquired businesses) in its open tax years. The earliest available NOLs were generated in the tax year beginning January 1, 1989, but are potentially subject to adjustment by the federal tax authorities in the tax year in which they are utilized. Thus, the Company's earliest U.S. federal income tax return that is closed to potential audit adjustments is the tax year ending December 31, 1988. The Company's most recent Canadian income tax return that is closed to potential audit adjustments is the tax year ended December 31, 2002.

        In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, "Fair Value Measurements" ("SFAS 157"). This statement clarifies the definition of fair value, establishes a framework for measuring fair value, and expands the disclosures on fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. We have not determined the effect, if any, the adoption of this statement will have on our financial position or results of operations.

        In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" ("SFAS 159"). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have not determined the effect, if any, the adoption of this statement will have on our financial position or results of operations.

31

---

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

        Forest Oil Corporation ("Forest") is an independent oil and gas company engaged in the acquisition, exploration, development, and production of natural gas and liquids in North America and selected international locations. 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.

        The following discussion and analysis should be read in conjunction with Forest's Condensed Consolidated Financial Statements and Notes thereto, the information under the heading "Forward-Looking Statements" below, and the information included in Forest's 2006 Annual Report on Form 10-K under the heading "Risk Factors", and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions." Unless the context otherwise indicates, references in this quarterly report on Form 10-Q to "Forest," "we," "ours," "us," or like terms refer to Forest Oil Corporation and its subsidiaries.

2007 OVERVIEW

Acquisition of Houston Exploration

        On June 6, 2007, Forest completed the acquisition of The Houston Exploration Company ("Houston Exploration") in a cash and stock transaction totaling $1.5 billion and the assumption of Houston Exploration's debt. Houston Exploration was an independent natural gas and oil producer engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. Houston Exploration had operations in four producing regions within the United States: South Texas, East Texas, the Arkoma Basin of Arkansas, and the Uinta and DJ Basins in the Rocky Mountains. The principal factors management considered in making the acquisition included the mix of complementary high-quality assets in certain of our existing core areas, lower-risk exploitation opportunities, expected increased cash flow from operations available for investing activities, and opportunities for cost savings through administrative and operational synergies. At the time the acquisition was announced on January 7, 2007, Forest estimated the Houston Exploration net oil and gas reserves to be 655 Bcfe, of which 65% were classified as proved developed and the remaining amounts were classified as proved undeveloped. Pursuant to the terms and conditions of the agreement and plan of merger ("Merger Agreement"), Forest paid total merger consideration of $750 million in cash and issued approximately 24 million common shares, valued at $30.28 per share. The per share value of the Forest common shares issued was calculated as the average of Forest's closing share price for a five day period surrounding the announcement date of the acquisition on January 7, 2007. The cash component of the merger consideration was financed from a private placement of $750 million of senior notes due 2019 and borrowings under our $1.0 billion second amended and restated credit facilities that were executed on June 6, 2007. Immediately following the completion of the merger, Forest repaid all of Houston Exploration's outstanding bank debt totaling $177 million. The revenues and expenses associated with Houston Exploration have been included in Forest's Condensed Consolidated Statements of Operations since June 6, 2007, the date the acquisition closed.

Sale of Alaska Assets

        On August 27, 2007, Forest sold substantially all of its Alaska assets (the "Alaska Assets") to Pacific Energy Resources Ltd. ("PERL"). Forest estimated the oil and gas reserves of the Alaska Assets to be approximately 181 Bcfe at December 31, 2006. The total consideration received for the Alaska Assets included $400 million in cash, 10 million restricted shares of PERL common stock, and a zero coupon senior subordinated note from PERL due 2014 in the principal amount at stated maturity of $60.8 million. A portion of the cash consideration, $269 million, was applied to prepay all amounts due under the Forest Alaska Credit Agreements, including accrued interest and prepayment premiums.

32

---

Amended Credit Facilities

        On June 6, 2007, Forest entered into second amended and restated U.S. and Canadian credit facilities in connection with the Houston Exploration acquisition which will mature in 2012. The initial Global Borrowing Base under the amended and restated credit facilities is $1.4 billion. Initial commitments consist of a U.S. facility of $850 million and a Canadian facility of $150 million for a total of $1.0 billion. See Bank Credit Facilities below for additional information regarding the amended and restated credit facilities.

Senior Notes Issuance

        On June 6, 2007, Forest issued $750 million of 7¹/4% senior notes due in 2019 ("the 7¹/4% Notes"). The net proceeds of the 7¹/4% Notes offering of $739.2 million, after deducting initial purchaser discounts, were used to fund a portion of the cash consideration for Forest's acquisition of Houston Exploration. Interest on the 7¹/4% Notes is payable semi-annually beginning December 15, 2007. Forest may redeem the 7¹/4% Notes at different intervals during the term of the notes. See 7¹/4% Senior Notes Due 2019 below for additional information.

Production Increase

        Production increased 67% during the three months ended September 30, 2007 from the corresponding period in 2006. The increase was primarily attributable to the additional production associated with the Houston Exploration acquisition partially offset by a reduction in production related to the sale of the Alaska Assets in August 2007.

Other Divestitures

        During the nine months ended September 30, 2007, Forest sold properties in addition to the Alaska Assets, including oil and gas properties with estimated proved reserves of approximately 14 Bcfe with production of approximately 2 MMcfe per day, for total proceeds of $39.1 million, including overriding royalty interests in Australia for cash proceeds of $7.2 million that resulted in a gain on the sale of $7.2 million ($4.5 million net of tax). In addition, in August 2007, Forest entered into a sale-leaseback transaction whereby it sold its drilling rigs for cash proceeds of $62.6 million and simultaneously entered into an operating lease with the buyer which provides for monthly rental payments of $.9 million for a term of seven years.

Debt Reduction

        We have previously stated a goal of maintaining financial leverage at 30-40% of book capitalization but may occasionally exceed this range when conditions warrant such as using leverage to make strategic acquisitions like the acquisition of Houston Exploration. In order to reduce leverage resulting from this acquisition, Forest completed various asset sales during the third quarter, including those discussed above, and was able to reduce its debt by $470 million in the third quarter and its debt-to-book capitalization to 42% at September 30, 2007.

33

---

RESULTS OF OPERATIONS

Oil and Gas Production and Revenues

        Production volumes, revenues, and weighted average sales prices by product and location for the three and nine months ended September 30, 2007 and 2006 were as follows:

			Three Months Ended September 30,
			2007									2006
			Gas (MMcf)			Oil (MBbls)		NGLs (MBbls)		Total (MMcfe)		Gas (MMcf)		Oil (MBbls)		NGLs (MBbls)		Total (MMcfe)
Production volumes:
	United States			29,038		1,114		715		40,012		10,838		1,264		431		21,008
	Canada			6,486		191		65		8,022		6,075		185		100		7,785
Totals				35,524		1,305		780		48,034		16,913		1,449		531		28,793
Revenues (in thousands):
	United States		$	161,305		80,407		27,971		269,683		59,721		85,067		14,914		159,702
	United States hedging gains (losses)			—		—		—		—		2,445		(4,695	)	—		(2,250	)
	Canada			28,680		11,923		2,731		43,334		28,130		10,785		4,553		43,468
Totals			$	189,985		92,330		30,702		313,017		90,296		91,157		19,467		200,920
Average sales price:
	United States		$	5.55		72.18		39.12		6.74		5.51		67.30		34.60		7.60
	United States hedging gains (losses)			—		—		—		—		.23		(3.71	)	—		(.11	)
	Canada			4.42		62.42		42.02		5.40		4.63		58.30		45.53		5.58
Totals			$	5.35		70.75		39.36		6.52		5.34		62.91		36.66		6.98

			Nine Months Ended September 30,
			2007									2006
			Gas (MMcf)			Oil (MBbls)		NGLs (MBbls)		Total (MMcfe)		Gas (MMcf)		Oil (MBbls)		NGLs (MBbls)		Total (MMcfe)
Production volumes:
	United States			55,099		3,558		1,672		86,479		38,010		3,979		1,198		69,072
	Canada			19,051		603		189		23,803		17,768		557		304		22,934
Totals				74,150		4,161		1,861		110,282		55,778		4,536		1,502		92,006
Revenues (in thousands):
	United States		$	327,746		222,363		58,951		609,060		242,971		256,321		39,502		538,794
	United States hedging losses			—		—		—		—		(19,475	)	(21,132	)	—		(40,607	)
	Canada			100,293		33,055		7,104		140,452		88,606		29,561		13,885		132,052
Totals			$	428,039		255,418		66,055		749,512		312,102		264,750		53,387		630,239
Average sales price:
	United States		$	5.95		62.50		35.26		7.04		6.39		64.42		32.97		7.80
	United States hedging losses			—		—		—		—		(0.51	)	(5.31	)	—		(.59	)
	Canada			5.26		54.82		37.59		5.90		4.99		53.07		45.67		5.76
Totals			$	5.77		61.38		35.49		6.80		5.60		58.37		35.54		6.85

        Net oil and gas production in the third quarter of 2007 was 48.0 Bcfe or an average of 522.1 MMcfe per day, a 67% increase from 28.8 Bcfe or an average of 313.0 MMcfe per day in the third quarter of 2006. The increase was primarily attributable to the additional production associated with the Houston Exploration acquisition partially offset by a reduction in production related to the sale of the Alaska Assets in August 2007. Net oil and gas production in the first nine months of 2007 was 110.3 Bcfe or an average of 404.0 MMcfe per day, a 20% increase from 92.0 Bcfe or an average of 337.0 MMcfe per day in the same period of 2006. The increase in the nine month period was primarily

34

---

due to the additional production volumes generated from the Houston Exploration acquisition in June 2007, which was partially offset by the spin-off of our offshore Gulf of Mexico properties in early March 2006 and the sale of the Alaska Assets in August 2007.

        Oil and natural gas revenues were $313.0 million during the three months ended September 30, 2007, a 56% increase as compared to $200.9 million for the same period in the prior year, which included realized hedging losses of $2.3 million. The increase in oil and natural gas revenues during the comparable three month periods was primarily due to the 67% increase in production volumes offset by an 8% decrease in the average realized price per Mcfe (before the effects of hedging) from the prior year period. Oil and natural gas revenues were $749.5 million during the nine months ended September 30, 2007, a 19% increase as compared to $630.2 million for the same period in the prior year, which included realized hedging losses of $40.6 million. The increase in oil and natural gas revenues during the comparable nine month periods was primarily due to the 20% increase in production volumes and a $40.6 million decrease in hedging losses on derivatives accounted for as cash flow hedges. These increases were offset by a 7% decrease in the average realized sales price per Mcfe (before the effects of hedging). No hedging gains or losses were included in the average sales prices presented for each period in 2007 because we elected to discontinue cash flow hedge accounting effective in March 2006. See Realized and Unrealized Gains and Losses on Derivative Instruments below for information on gains and losses recognized on derivative instruments not designated as cash flow hedges.

Oil and Gas Production Expense

        The table below sets forth the detail of oil and gas production expense, for the three and nine months ended September 30, 2007 and 2006:

			Three Months Ended September 30,					Nine Months Ended September 30,
			2007			2006		2007		2006
			(Dollar Amounts In Thousands, Except per Mcfe Data)
Lease operating expenses:
	Direct operating expense and overhead		$	41,825		31,382		112,559		98,500
	Workover expense			6,444		3,581		16,777		17,323
Lease operating expenses			$	48,269		34,963		129,336		115,823
Lease operating expenses per Mcfe			$	1.00		1.21		1.17		1.26
Production and property taxes			$	16,112		8,974		36,830		30,699
Production and property taxes as a percentage of oil and gas revenues, excluding hedging losses				5.1	%	4.4	%	4.9	%	4.6	%
Transportation and processing costs			$	5,764		5,494		15,216		15,865
Transportation and processing costs per Mcfe			$	.12		.19		.14		.17

Lease Operating Expenses

        Lease operating expenses decreased 17% on a per-Mcfe basis in the third quarter of 2007 to $1.00 per Mcfe from $1.21 per Mcfe in the third quarter of 2006. Lease operating expenses on a per-Mcfe basis were 7% lower during the first nine months of 2007 compared to the same period in 2006. The decrease in each period was primarily due to lower average per-unit lease operating expenses from the assets acquired from Houston Exploration and general cost reduction initiatives. Lease operating expense for the nine months ended September 30, 2006 also included two months of offshore Gulf of

35

---

Mexico operations, before the spin-off of these properties on March 2, 2006, which had an average per-unit lease operating cost of $2.21 per Mcfe.

Production and Property Taxes

        Production and property taxes were higher during the three and nine month periods ending September 30, 2007 compared to the same periods in the prior year and are due to the acquisition of Houston Exploration. Production and property taxes as a percentage of oil and gas sales, excluding hedging losses, are generally consistent for all periods presented. Normal fluctuations will occur between periods based on the approval of incentive tax credits and due to changes in tax rates or valuation assessments.

Transportation and Processing Costs

        Transportation and processing costs increased slightly to $5.8 million, or $.12 per Mcfe, in the three months ended September 30, 2007, from $5.5 million, or $.19 per Mcfe, for the corresponding 2006 period. Transportation and processing costs decreased slightly to $15.2 million, or $.14 per Mcfe, in the nine months ended September 30, 2007, from $15.9 million, or $.17 per Mcfe, for the corresponding 2006 period. The decrease on a per-Mcfe basis for each period was due primarily to the lower processing and transportation costs incurred in Canada and Alaska.

General and Administrative Expense

        The following table summarizes the components of general and administrative expense and stock-based compensation expense incurred during the three and nine month periods ended September 30, 2007 and 2006:

		Three Months Ended September 30,					Nine Months Ended September 30,
		2007			2006		2007		2006
		(In Thousands, Except per Mcfe Data)
Total general and administrative costs		$	24,272		14,688		60,872		44,127
General and administrative costs capitalized			(10,319	)	(5,713	)	(25,262	)	(17,297	)
General and administrative expense		$	13,953		8,975		35,610		26,830
General and administrative expense per Mcfe		$	.29		.31		.32		.29
Total stock-based compensation costs		$	5,140		2,492		12,023		18,688
Stock-based compensation costs capitalized			(2,377	)	(919	)	(4,539	)	(6,763	)
Stock-based compensation expense		$	2,763		1,573		7,484		11,925
Stock-based compensation expense per Mcfe		$	.06		.05		.07		.13
Total general and administrative expense including stock-based compensation		$	16,716		10,548		43,094		38,755

        The increase in general and administrative expense for the three and nine month periods in 2007 of $5.0 million and $8.8 million, respectively, as compared to the same periods in 2006 is primarily related to increased employee salary and benefit costs due to additional employees related to the acquisition of Houston Exploration. Stock-based compensation expense increased $1.2 million and decreased $4.4 million during the three and nine month periods in 2007, respectively, as compared to the same periods in 2006. The increase in stock-based compensation for the three month period was due to additional stock-based awards granted in 2007. The decrease in stock-based compensation during the first nine months of 2007 as compared to 2006 was the result of the partial settlement of our restricted stock awards and phantom stock unit awards in connection with the spin-off of the Gulf of Mexico operations on March 2, 2006.

36

---

Depreciation and Depletion

        Depreciation, depletion and amortization expense ("DD&A") for the three months ended September 30, 2007 was $122.0 million as compared to $62.5 million for the same period in 2006. On an equivalent Mcf basis, DD&A expense was $2.54 per Mcfe for the three months ended September 30, 2007 as compared to $2.17 per Mcfe for the same period in the prior year. The increase of $.37 per Mcfe in 2007 was primarily due to the acquisition of Houston Exploration, which had higher than historical rates associated with it. DD&A for the nine months ended September 30, 2007 was $268.6 million as compared to $203.4 million for the same period in 2006. On an equivalent Mcf basis, DD&A expense was $2.44 per Mcfe for the nine months ended September 30, 2007 as compared to $2.21 per Mcfe for the same period in the prior year. The increase of $.23 per Mcfe was primarily due to the acquisition of Houston Exploration offset by the spin-off of the Gulf of Mexico operations in March 2006.

Interest Expense

        Interest expense in the third quarter of 2007 totaled $32.6 million as compared to $19.1 million in the third quarter of 2006. Interest expense during the first nine months of 2007 totaled $86.0 million as compared to $51.6 million in the same period of 2006. The increase in interest expense during each period in 2007 compared to the corresponding period in 2006 was due to increased average debt balances due to the acquisition of Houston Exploration and higher average interest rates primarily associated with the Forest Alaska Credit Agreements, which were repaid in August 2007, offset by an increase in capitalized interest. Interest costs related to significant unproved properties that are under development are capitalized to oil and gas properties under the full cost method of accounting. Forest capitalized interest expense of $6.3 million and $.4 million during the three months ended September 30, 2007 and 2006, respectively, and $8.5 million and $2.4 million during the nine months ended September 30, 2007 and 2006, respectively. The increase in interest capitalized is due to the acquisition of Houston Exploration, which included a large investment in unproved properties.

Realized and Unrealized Gains and Losses on Derivative Instruments

        The table below sets forth realized and unrealized gains and losses on derivatives recognized under "Other income and expense" in our Condensed Consolidated Statements of Operations for the periods indicated. Since March 2006, when Forest elected to discontinue cash flow hedge accounting for all of its derivative instruments, Forest has recognized all mark-to-market gains and losses in earnings, rather than deferring any such amounts in "Accumulated other comprehensive income" in shareholders' equity. In addition, cash settlements on derivative instruments are recorded as "Realized gains and losses on derivative instruments" in other income and expense in the Condensed Consolidated Statements of Operations rather than an adjustment to "Oil and gas sales" or "Interest expense". See

37

---

Note 9 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.

			Three Months Ended September 30,					Nine Months Ended September 30,
			2007			2006		2007		2006
			(In Thousands)
Realized losses (gains) on derivatives:
	Oil		$	3,418		16,559		(17,346	)	37,595
	Gas			(33,596	)	(3,676	)	(47,106	)	(7,099	)
	Interest			(209	)	—		(339	)	—
Total			$	(30,387	)	12,883		(64,791	)	30,496
Unrealized losses (gains) on derivatives:
	Oil		$	17,494		(59,532	)	61,538		(32,805	)
	Gas			(8,314	)	(18,382	)	(27,543	)	(35,373	)
	Interest			3,235		—		1,445		—
Total			$	12,415		(77,914	)	35,440		(68,178	)

Unrealized Foreign Currency Exchange Gains and Losses

        Unrealized foreign currency exchange gains and losses relate to intercompany indebtedness between Forest Oil Corporation and our Canadian subsidiary. The intercompany debt is denominated in U.S. dollars and with the recent strength in the Canadian dollar, unrealized foreign currency gains have been recorded for each period in 2007.

Unrealized Gain on Other Investments

        For the three and nine month periods ended September 30, 2007, Forest recorded an unrealized gain on other investments of $2.5 million related to the PERL common stock received as a portion of the consideration in the sale of the Alaska Assets in August 2007.

Current and Deferred Income Tax Expense

        Forest recorded income tax expense of $29.0 million in the three months ended September 30, 2007, as compared to $48.3 million in the comparable period of 2006. Our effective tax rate for the three months ended September 30, 2007 of 33.4% was lower than our statutory rate for the period of approximately 36% due to the release of valuation allowances on capital loss carryforwards in Canada and capital gains in Canada which are taxed at 50% of statutory rates. Our effective tax rate for the three months ended September 30, 2006 was 38.6%, which approximated our statutory rate for the period of approximately 38%.

        Forest recorded income tax expense of $67.1 million and $68.5 million in the nine months ended September 30, 2007 and 2006, respectively. Our effective tax rates for the nine months ended September 30, 2007 and 2006 were 32.1% and 33.6%, respectively. The low effective tax rate for the nine months ended September 30, 2007 relative to our statutory rate was primarily due to statutory rate reductions enacted in Canada, the release of valuation allowances, lower apportioned state income tax rates, and capital gains in Canada that are taxed at 50% of statutory rates. The low effective tax rate for the nine months ended September 30, 2006 relative to our statutory rate was primarily due to 2006 statutory rate reductions enacted in Canada and changes in the Texas income tax law partially offset by non-deductible spin-off costs and an increase in our estimated combined state income tax rates resulting from the spin-off of our offshore Gulf of Mexico operations.

38

---

Impairments of International Properties

        During the second quarter of 2006, Forest recorded an impairment of $2.1 million related to certain properties located in Gabon. The Gabon impairment was related to historical costs impaired to reflect a drilled dry hole.

Liquidity and Capital Resources

        We expect our cash flow from operations to be our primary source of liquidity to meet operating expenses and fund capital expenditures other than large acquisitions. Any remaining cash flow from operations will be available for acquisitions, in whole or in part, or other corporate purposes, including the repayment of indebtedness.

        The prices we receive for our oil and natural gas production have a significant impact on operating cash flows. While significant price declines would adversely affect the amount of cash flow generated from operations, we utilize a hedging program to partially mitigate that risk. As of November 1, 2007, Forest has hedged approximately 75 Bcfe of its 2008 production. This level of hedging provides a measure of certainty of the cash flow we will receive for a portion of our production in 2008. Depending on changes in oil and gas futures markets and management's view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions. For further information concerning our hedging contracts, see Item 3—"Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk", below.

        Our revolving U.S. and Canadian bank credit facilities, which were amended and restated in June 2007, provide another source of liquidity. These credit facilities, which mature in June 2012, are used to fund daily operating activities and acquisitions in the United States and Canada as needed. See "Bank Credit Facilities" below for details.

        The public capital markets have been our principal source of funds to finance large acquisitions. We have issued debt and equity securities in both public and private offerings in the past, including the second quarter of 2007, and we expect that these sources of capital will continue to be available to us in the future for acquisitions. Nevertheless, ready access to capital on reasonable terms can be impacted by our debt ratings assigned by independent rating agencies and are subject to many uncertainties, including restrictions contained in our bank credit facilities and indentures for our senior notes, macroeconomic factors outside of our control, and other risks as explained in Part 1, Item 1A—"Risk Factors" of our 2006 Annual Report on Form 10-K and Part II, Item 1A of this Report.

        We believe that our available cash, cash provided by operating activities, and funds available under our bank credit facilities will be sufficient to fund our operating, interest, and general and administrative expenses, our capital expenditure budget, and our short-term contractual obligations at current levels for the foreseeable future, including the ability to redeem the $265 million in 8% senior notes due in June 2008.

Bank Credit Facilities

        On June 6, 2007, Forest entered into amended and restated credit facilities totaling $1.0 billion. The amended and restated facilities consist of a $850 million U.S. credit facility (the "U.S. Facility") through a syndicate of banks led by JPMorgan Chase Bank, N.A. and a $150 million Canadian credit facility (the "Canadian Facility", and together with the U.S. Facility, the "Credit Facilities") through a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Credit Facilities mature in June 2012. Subject to the agreement of Forest and the applicable lenders, the size of the Credit Facilities may be increased by $800 million in the aggregate.

        Forest's availability under the Credit Facilities will be governed by a borrowing base ("Global Borrowing Base") which currently is set at $1.4 billion, with $1.25 billion allocated to the U.S. credit

39

---

facility and $150 million allocated to the Canadian credit facility. The determination of the Global Borrowing Base is made by the lenders in their sole discretion taking into consideration the estimated value of Forest's oil and gas properties in accordance with the lenders' customary practices for oil and gas loans. The Global Borrowing Base is redetermined semi-annually and the available borrowing amount could be increased or decreased as a result of such redeterminations. In addition, Forest and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the Global Borrowing Base redetermined.

        The Credit Facilities include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and include financial covenants. Interest rates and collateral requirements under the Credit Facilities will vary based on Forest's credit ratings and financial condition, as governed by certain financial tests.

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

        The Credit Facilities are collateralized by Forest's assets. Forest is required to mortgage, and grant a security interest in, 75% of the present value of the proved oil and gas properties and related assets of Forest and its subsidiaries. If Forest's corporate credit ratings by Moody's and S&P meet pre-established levels, the security requirements would cease to apply and at Forest's request the banks would release their liens and security interest on Forest's properties.

        From time to time, Forest and the syndication agents, documentation agents, global administrative agent and the other lenders party to the Credit Facilities, engage in other transactions, including securities offerings where such parties or their affiliates, may serve as an underwriter or initial purchaser of Forest's securities and, or serve as counterparties to Forest's hedging arrangements.

        At September 30, 2007, there were outstanding borrowings of $115.0 million under the U.S. credit facility at a weighted average interest rate of 6.67%, and there were outstanding borrowings of $111.6 million under the Canadian credit facility at a weighted average interest rate of 6.4%. We also had used the Credit Facilities for approximately $2.6 million in letters of credit, leaving an unused borrowing amount under the Credit Facilities of approximately $770.8 million at September 30, 2007.

Term Loan Financing Agreements

        On December 8, 2006, Forest, through its wholly-owned subsidiaries, Forest Alaska Operating LLC and Forest Alaska Holding LLC (together "Forest Alaska"), issued, on a non-recourse basis to Forest, term loan financing facilities in the aggregate principal amount of $375 million. The issuance was comprised of two term loan facilities, including a $250 million first lien credit agreement and a $125 million second lien credit agreement (together the "Credit Agreements"). The loan proceeds were used to fund a $350 million distribution to Forest, which Forest used to pay down its U.S. credit facility, and to provide Forest Alaska working capital for its operations and pay transaction fees and expenses.

        During the nine months ended September 30, 2007, Forest made scheduled prepayments of $1.3 million and a voluntary repayment of $110.0 million on the first lien credit agreement. In

40

---

conjunction with the sale of the Alaska Assets on August 27, 2007, Forest used a portion of the $400 million cash consideration to repay the remaining $263.8 million principal balance outstanding under the Credit Agreements.

7¹/4% Senior Notes Due 2019

        On June 6, 2007, Forest issued $750 million of 7¹/4% senior notes due in 2019 at par for net proceeds of $739.2 million, after deducting initial purchaser discounts, which were used to fund a portion of the cash merger consideration for Forest's acquisition of Houston Exploration. The 7¹/4% Notes were issued under an indenture (the "Indenture") dated as of June 6, 2007 among Forest, Forest Oil Permian Corporation, a wholly-owned subsidiary of Forest ("Forest Permian"), as subsidiary guarantor, and U.S. Bank National Association, as trustee. The 7¹/4% Notes are jointly and severally guaranteed by Forest Permian on an unsecured basis. Interest is payable on June 15 and December 15 of each year, beginning December 15, 2007. The 7¹/4% Notes will mature on June 15, 2019.

Cash Flow

        Net cash provided by operating activities, net cash used in investing activities, and net cash provided by financing activities for the nine months ended September 30, 2007 and 2006 were as follows:

        The increase in net cash provided by operating activities of $174.2 million in the nine months ended September 30, 2007 as compared to the same period in 2006 was primarily due to higher net income before non-cash charges and a decreased investment in net operating assets and liabilities in the first nine months of 2007 as compared to the same period in 2006. The increase in cash used in investing activities of $83.6 million during the nine months ended September 30, 2007 as compared to the corresponding period in 2006 was primarily due to the cash used in the acquisition of Houston Exploration of $776.0 million (including cash consideration, cash settlement of stock options, and direct merger costs) in June 2007 as compared to approximately $255 million used to fund our purchase of the Cotton Valley assets in East Texas in 2006 offset by the proceeds from the sale of the Alaska Assets and other properties during the first nine months of 2007 for aggregate proceeds of $501.7 million. Net cash provided by financing activities in the nine months ended September 30, 2007 included the issuance of the 7¹/4% Notes for net proceeds of $739.2 million, net bank proceeds of $104.2 million, and proceeds from the exercise of stock options and from the employee stock purchase plan of $8.1 million offset by the repayment of Houston Exploration's bank debt of $176.9 million and repayments on the term loans of $375.0 million. Net cash provided by financing activities in the nine months ended September 30, 2006 included net bank proceeds of $389.0 million. The 2006 period also included $21.7 million of proceeds from the spin-off of our Gulf of Mexico operations and proceeds from the exercise of stock options and from the employee stock purchase plan of approximately $5.2 million.

41

---

Capital Expenditures

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

---

(1)

Total capital expenditures include both cash expenditures, accrued cash expenditures, and non-cash capital expenditures including stock issued for properties and stock-based compensation capitalized under the full cost method of accounting.

(2)

Does not include the effect of estimated discounted asset retirement obligations.

        For the nine months ended September 30, 2007, expenditures for exploration and development activities totaled $547.2 million. Forest's anticipated expenditures for exploration and development in 2007 are estimated to range from $760 million to $810 million. Some of the factors impacting the level of capital expenditures in 2007 include crude oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, and weather disruptions.

Forward-Looking Statements

        The information in this Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts 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 are forward-looking statements. Generally, the words "expects," "anticipates," "targets," "goals," "projects," "intends," "plans," "believes," "seeks," "estimates," variations of such words and similar expressions identify forward-looking statements, and any statements regarding Forest's future financial condition, results of operations and business, are also forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included in Part I of our 2006 Annual Report on Form 10K and Part II, Item 1A of this Report.

42

---

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

•

estimates of our oil and gas reserves;



•

estimates of our future natural gas and liquids production, including estimates of any increases in oil and gas production;



•

the amount, nature and timing of capital expenditures, including future development costs, and availability of capital resources to fund capital expenditures;



•

the amount, nature and timing of any synergies or other benefits expected to result from acquisitions, including the merger with Houston Exploration;



•

our outlook on oil and gas prices;



•

the impact of political and regulatory developments;



•

our future financial condition or results of operations and our future revenues and expenses; and



•

our business strategy and other plans and objectives for future operations.

        We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described in the Form 10-K and this Report under the caption "Risk Factors." The financial results of our foreign operations are also subject to currency exchange rate risks.

        Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

        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.

        All forward-looking statements, expressed or implied, included in this Form 10-Q and attributable to Forest are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Forest or persons acting on its behalf may issue. Forest does not undertake to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-Q with the Securities and Exchange Commission, except as required by law.

43

---

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

        We produce and sell natural gas, crude oil, and natural gas liquids for our own account in the United States and Canada. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. In order to reduce the impact of fluctuations in prices on our revenues, or to protect the economics of property acquisitions, we make use of an oil and gas hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other financial instruments with counterparties who, in general, are participants in our credit facilities. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.

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, 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, 2007, we had entered into the following swaps:

		Swaps
		Natural Gas (NYMEX HH)								Oil (NYMEX WTI)
		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)
Fourth Quarter 2007		60		$	7.88		$	4,848		7,000		$	70.03		$	(3,771	)
Calendar 2008		10			9.10			4,072		6,500			69.72			(13,947	)
Calendar 2009		—			—			—		4,500			69.01			(9,772	)
Calendar 2010		—			—			—		1,500			72.95			(837	)

        Forest also uses basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX price and the index price at which the hedged gas is sold. As of September 30, 2007, we had entered into the following basis swaps:

---

(1)

Included in Forest's outstanding basis swaps at September 30, 2007 are basis swaps assumed in the Houston Exploration acquisition with a fair value of $1.3 million. At September 30, 2007, these basis swaps are for 80 Bbtu per day for the fourth quarter 2007 and January – February 2008.

Costless Collars

        Forest also enters into costless collar agreements with third parties. A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price; and we pay the difference between the ceiling price and

44

---

the index price only if the index price is above the ceiling price. As of September 30, 2007, we had entered into the following collars:

		Costless Collars(1)
		Natural Gas (NYMEX HH)								Oil (NYMEX WTI)
		Bbtu per Day		Weighted Average Hedged Floor and Ceiling Price per MMBtu			Fair Value (In Thousands)			Barrels per Day		Weighted Average Hedged Floor and Ceiling Price per Bbl			Fair Value (In Thousands)
Fourth Quarter 2007		145		$	7.42/9.27		$	8,783		4,000		$	65.81/87.18		$	(218	)
January – February 2008		130			7.39/8.89			1,303		—			—			—
March – December 2008		70			7.23/8.85			(3,782	)	—			—			—

---

(1)

Included in Forest's outstanding natural gas costless collars at September 30, 2007 are natural gas costless collars assumed in the Houston Exploration acquisition with a fair value of $(10.8) million. At September 30, 2007, these costless collars had weighted average hedged floor and ceiling prices per MMBtu of $7.00/8.49 for 110 Bbtu per day for the fourth quarter 2007, $7.20/8.51 for 100 Bbtu per day for January – February 2008, and $5.00/5.72 for 20 Bbtu per day for March – December 2008.

Three-Way Costless Collars

        Forest also enters into three-way costless collars with third parties. These instruments establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, Forest receives the difference between the two floors. If the index price is between the two floors, Forest receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, Forest does not receive or pay any amounts. If the index price is above the ceiling, Forest pays the excess over the ceiling price. As of September 30, 2007, we had entered into the following three-way collars:

		Three-Way Costless Collars
		Natural Gas (NYMEX HH)
		Bbtu per Day		Weighted Average Hedged Lower Floor, Upper Floor, and Ceiling Price per MMBtu			Fair Value (In Thousands)
January – February 2008		20		$	6.00/8.00/10.00		$	402
March – December 2008		30			6.00/8.00/10.00			3,022

        The fair value of our commodity derivative instruments based on the futures prices quoted on September 30, 2007 was a net liability of $7.5 million.

        In October 2007, Forest entered into four additional natural gas swap agreements covering 40 Bbtu per day for calendar 2008 at a weighted average hedged price per MMBtu of $8.20 with 10 Bbtu per day subject to a $6.00 written put. In November 2007, Forest entered into a natural gas costless collar agreement covering 10 Bbtu per day for the period March – December 2008 at hedged floor and ceiling prices per MMBtu of $8.00 and $9.00, respectively.

45

---

Fair Value Reconciliation

        The following table reconciles the changes that occurred in the fair values of our open derivative contracts during the nine months ended September 30, 2007, beginning with the fair value of our derivative contracts on December 31, 2006:

Foreign Currency Exchange Risk

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

Interest Rate Risk

        The following table presents principal amounts and related weighted average fixed interest rates by year of maturity for Forest's debt obligations and the fair value of our debt obligations at September 30, 2007:

			2008			2011		2012		2013		2014		2019		Total		Fair Value
			(Dollar Amounts In Thousands)
Bank credit facilities:
	Variable rate		$	—		—		226,577		—		—		—		226,577		226,577
	Average interest rate(1)			—		—		6.53	%	—		—		—		6.53	%
Short-term debt:
	Fixed rate		$	265,000		—		—		—		—		—		265,000		267,650
	Coupon interest rate			8.00	%	—		—		—		—		—		8.00	%
	Effective interest rate(2)			7.13	%	—		—		—		—		—		7.13	%
Long-term debt:
	Fixed rate		$	—		285,000		—		5,822		150,000		750,000		1,190,822		1,203,760
	Coupon interest rate			—		8.00	%	—		7.00	%	7.75	%	7.25	%	7.58	%
	Effective interest rate(2)			—		7.71	%	—		7.00	%	6.56	%	7.25	%	7.27	%

---

(1)

As of September 30, 2007.

(2)

The effective interest rate on the 8% Senior Notes due 2008, the 8% Senior Notes due 2011, and the 7³/4% Senior Notes due 2014 is reduced from the coupon rate as a result of amortization of gains related to the termination of related interest rate swaps.

46

---

Interest Rate Swaps

        Forest holds two floating to fixed interest rate swaps. One is a $75 million floating to fixed interest rate swap for three years at a one month LIBOR fixed rate of 4.80% and the other is a $112.5 million floating to fixed interest rate swap for three years at a one month LIBOR fixed rate of 4.96%. At September 30, 2007, the fair value of these interest rate swaps was a liability of $1.4 million.

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, H. Craig Clark, and our Chief Financial Officer, David H. Keyte, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a—15(e) and 15d—15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of the end of the quarterly period ended September 30, 2007 (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 Securities Exchange Act of 1934 (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, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

47

---

PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

        On June 6, 2007, Forest acquired The Houston Exploration Company pursuant to an agreement and plan of merger. In connection with the acquisition, on June 6, 2007, Houston Exploration was merged with and into Forest, with Forest continuing as the surviving entity. Houston Exploration's directors and Forest were named as defendants in a shareholder lawsuit brought by the City of Monroe Employees' Retirement System (the "Plaintiff") on June 22, 2006 in State court in Houston, Texas. On August 2, 2007, Plaintiff filed with the court a notice of nonsuit without prejudice and a request for dismissal. The court approved the request for dismissal on August 10, 2007.

Item 1A. RISK FACTORS

        The following risk factors update the Risk Factors included in our Annual Report on Form 10-K for fiscal year ended December 31, 2006 ("Annual Report"). Except as set forth below, there have been no material changes to the risks described in Part I, Item 1A, of our Annual Report.

Lower oil and gas prices and other factors may cause us to record ceiling test writedowns.

        We use the full cost method of accounting to report our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "ceiling limit," which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling test writedown." Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test writedown would not impact cash flow from operating activities, but it would reduce our shareholders' equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. We cannot assure you that we will not experience ceiling test writedowns in the future. Our Canadian full cost pool, in particular, could be adversely impacted by moderate declines in commodity prices. In addition, our ceiling test cushion is subject to fluctuation as a result of our corporate development activity which is difficult to fully assess prior to completion. For example, our acquisition of Houston Exploration in June 2007 is expected to increase the risk of a ceiling test writedown in the future and the sale of our Alaska Assets in August 2007 was expected to have an unfavorable impact on the third quarter ceiling test. At September 30, 2007, the ceiling test cushion was negatively impacted by the Houston Exploration merger and the sale of the Alaska Assets, but the impact of these activities was offset by favorable third quarter results associated with Forest's properties.

We have substantial debt, which may materially affect our operations.

        As of September 30, 2007, the principal amount of our outstanding consolidated debt was approximately $1.7 billion, including approximately $226.6 million outstanding under the combined U.S. and Canadian bank credit facilities among Forest and its Canadian subsidiary. Our debt represented 42% of our total capitalization at September 30, 2007. Further, we may incur additional debt in the future, including in connection with acquisitions and refinancings.

48

---

        The level of our debt has several important effects on our operations. In particular, it could:

•

require us to dedicate a significant portion of our cash flow from operations to the payment of indebtedness, thereby reducing the availability to fund working capital, capital expenditures, and other general corporate purposes;



•

increase our costs as credit rating agencies have changed, and may change in the future, their ratings of our debt and other obligations as a result of changes in our debt level, financial condition, earnings, and cash flow; and these changes may impact the costs, terms, conditions, and availability of financing;



•

impact our operations as covenants contained in our existing and future credit and debt arrangements require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;



•

burden our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate, and other purposes as any such financing may be subject to increased costs or more restrictive covenants;



•

place us at a competitive disadvantage compared to similar companies that have less debt; and



•

increase our vulnerability to adverse economic and industry conditions.

Our International operations may be adversely affected by currency fluctuations and economic and political developments.

        We currently have oil and gas operations in Canada, Italy, Gabon, and South Africa. As a result, we are exposed to the risks of international operations, including political and economic developments, royalty and tax increases, changes in laws or policies affecting our exploration and development activities, and currency exchange risks, as well as changes in the policies of the United States affecting trade, taxation, and investment in other countries. We have significant operations in Canada. For the nine months ended September 30, 2007, the revenues and expenses of such operations represented approximately 19% of our consolidated oil and gas revenues and 18% of our consolidated production costs. The revenues and expenses of these operations are denominated in Canadian dollars. As a result, the profitability of our Canadian operations is subject to the risk of fluctuations in the exchange rates between the U.S. dollar and Canadian dollar. In addition, our Canadian operations may be adversely affected by recent regulatory developments. The majority of our Canadian operations are located in Alberta, Canada, and, in October 2007, the Alberta Government announced a new oil and gas royalty framework to take effect in January 2009. We are evaluating the new royalty structure and its impact on our Canadian operations, which could have an adverse effect on our Canadian operations and financial performance.

        Although we do not have material operations in Italy, Gabon and South Africa and have not assigned any proved reserves to our properties in these countries, our ongoing operations may be adversely affected by political, economic and regulatory developments, changes in the local royalty and tax regimes, and currency fluctuations. In South Africa, we have an interest in offshore properties that have tested natural gas. While no proved reserves have been assigned to these properties as commercial sales contracts have not been established, and if we are unable to arrange for commercial use of these properties, we may not be able to recoup our investment and may not realize our anticipated financial and operating results from these properties. The South African government adopted legislation in 2002 to revise the process pursuant to which it grants petroleum exploration and production licenses and issued the implementing regulations in 2004. Under the new regulations, we have applied to the government to convert one existing prospecting sublease into an exploration right. In addition, we have applied for a production right covering the geographic area of our other existing prospecting sublease. The government has not taken final action on these applications. We cannot predict whether these

49

---

applications will be granted or whether any granted rights will meet our economic or operational requirements, in which event we may choose to relinquish these leases and lose our investment, which totals approximately $50 million.

        In addition, over the last several years, we have increased the level of drilling and related development activities in Italy and are currently working to obtain approvals necessary to construct pipelines and facilities and bring two wells on production, which is expected to occur in the first half of 2009. Fluctuations in the exchange rates between the U.S. dollar and the euro may adversely impact our expenses and our profitability models.

Item 6. EXHIBITS

(a)

Exhibits.

---

+

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.

50

---

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)
November 8, 2007
		By:		/s/  DAVID H. KEYTE       David H. Keyte Executive Vice President and Chief Financial Officer (on behalf of the Registrant and as Principal Financial Officer)
		By:		/s/  VICTOR A. WIND       Victor A. Wind Corporate Controller (Principal Accounting Officer)

51

---

Exhibit Index

Exhibit Number		Description
10.1		Amendment No. 4 to Forest Oil Corporation 2001 Stock Incentive Plan dated June 5, 2007.
10.2		Amendment to Forest Oil Corporation Salary Deferral Deferred Compensation Plan dated August 30, 2007.
10.3		First Amendment to Forest Oil Corporation Executive Deferred Compensation Plan as Amended and Restated Effective as of January 1, 2005.
10.4		Amendment to Forest Oil Corporation Amended and Restated 2005 Salary Deferred Compensation Plan dated August 30, 2007.
10.5		Form of Amendment to Grandfathered Senior Vice President Severance Agreement.
10.6		Form of Amendment to Senior Vice President Severance Agreement.
10.7		Form of Amendment to Grandfathered Vice President Severance Agreement.
10.8		Form of Amendment to Vice President Severance Agreement.
31.1		Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
31.2		Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
32.1+		Certification of Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
32.2+		Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

---

+

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.

52

---

QuickLinks

FOREST OIL CORPORATION INDEX TO FORM 10-Q September 30, 2007
PART I—FINANCIAL INFORMATION
FOREST OIL CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (In Thousands, Except Share Data)
FOREST OIL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
FOREST OIL CORPORATION CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (Unaudited)
FOREST OIL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
FOREST OIL CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
CONDENSED CONSOLIDATING BALANCE SHEETS (Unaudited) (In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited) (In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited) (In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited) (In Thousands)

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 4. CONTROLS AND PROCEDURES

PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS
Item 1A. RISK FACTORS
Item 6. EXHIBITS

SIGNATURES
Exhibit Index