Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 10-Q

(Mark One)ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended March 31, 2009Oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                             to


Commission File Number 1-13515

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

New York(State or other jurisdiction of
incorporation or organization)

25-0484900(I.R.S. Employer Identification No.)


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

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

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

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

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

Large accelerated filer ý

Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o


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

As of April 30, 2009 there were 97,074,820 shares of the registrant's common stock, par value $.10 per share, outstanding.



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FOREST OIL CORPORATION  INDEX TO FORM 10-Q  March 31, 2009



Part IFINANCIAL INFORMATION

1Item 1Financial Statements

1Condensed Consolidated Balance Sheets as of March 31, 2009 and December 31,
2008

1Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2009
and 2008

2Condensed Consolidated Statement of Shareholders' Equity for the Three Months
Ended March 31, 2009

3Condensed Consolidated Statements of Cash Flows for the Three Months Ended
March 31, 2009 and 2008

4Notes to Condensed Consolidated Financial Statements

5Item 2Management's Discussion and Analysis of Financial Condition and Results of Operations

31Item 3Quantitative and Qualitative Disclosures About Market Risk

46Item 4Controls and Procedures

49Part IIOTHER INFORMATION

50Item 1ARisk Factors

50Item 2Unregistered Sales of Equity Securities and Use of Proceeds

54Item 6Exhibits

54Signatures

55


i

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Table of Contents

PART IFINANCIAL INFORMATION

Item 1.    FINANCIAL STATEMENTS

FOREST OIL CORPORATION        CONDENSED CONSOLIDATED BALANCE SHEETS        (Unaudited)        (In Thousands,
Except Share Data)

March 31,
2009

December 31,
2008ASSETSCurrent assets:Cash and cash equivalents

$
856


2,205Accounts receivable


113,030


157,226Derivative instruments


230,853


169,387Other investments





2,327Inventory


74,644


78,683Other current assets


62,622


63,221Total current assets


482,005


473,049Property and equipment, at cost:Oil and gas properties, full cost method of accounting:Proved, net of accumulated depletion of $7,159,819 and $5,502,782


2,053,997


3,449,510Unproved


898,058


964,027Net oil and gas properties


2,952,055


4,413,537Other property and equipment, net of accumulated depreciation and amortization of $40,993 and $37,260


117,392


99,627Net property and equipment


3,069,447


4,513,164Deferred income taxes


136,576


Goodwill


253,158


253,646Derivative instruments


19,873


4,608Other assets


50,275


38,331$
4,011,334


5,282,798LIABILITIES AND SHAREHOLDERS' EQUITYCurrent liabilities:Accounts payable and accrued liabilities

$
263,395


424,941Accrued interest


39,830


7,143Derivative instruments


8,006


1,284Deferred income taxes


75,711


54,583Asset retirement obligations


3,477


5,852Other current liabilities


23,559


27,608Total current liabilities


413,978


521,411Long-term debt


2,934,489


2,735,661Asset retirement obligations


96,167


91,139Derivative instruments


6,092


2,600Deferred income taxes





185,587Other liabilities


71,443


73,488Total liabilities


3,522,169


3,609,886Shareholders' equity:Preferred stock, none issued and outstanding





Common stock, 97,074,098 and 97,039,751 shares issued and outstanding


9,707


9,704Capital surplus


2,361,716


2,354,903Accumulated deficit


(1,907,066
)

(729,293
)Accumulated other comprehensive income


24,808


37,598Total shareholders' equity


489,165


1,672,912$
4,011,334


5,282,798


See accompanying Notes to Condensed Consolidated Financial Statements.

1

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FOREST OIL CORPORATION        CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS        (Unaudited)

Three Months Ended
March 31,2009

2008(In Thousands, Except
Per Share Amounts)Revenues

$
194,667


376,530Operating expenses:Lease operating expenses


41,231


37,565Production and property taxes


11,695


20,051Transportation and processing costs


5,244


4,925General and administrative (including stock-based compensation)


16,085


19,288Depreciation and depletion


104,552


115,567Accretion of asset retirement obligations


2,038


1,784Ceiling test write-down of oil and gas properties


1,575,843


Total operating expenses


1,756,688


199,180Earnings (loss) from operations


(1,562,021
)

177,350Other income and expense:Interest expense


36,545


27,857Realized and unrealized (gains) losses on derivative instruments, net


(139,328
)

145,876Unrealized foreign currency exchange losses, net


3,539


2,775Unrealized losses on other investments, net


2,327


7,091Other expense, net


3,016


837Total other income and expense


(93,901
)

184,436Loss before income taxes


(1,468,120
)

(7,086
)Income tax:Current


1,268


(22
)Deferred


(291,615
)

(2,332
)Total income tax


(290,347
)

(2,354
)Net loss

$
(1,177,773
)

(4,732
)Basic loss per common share

$
(12.32
)

(.05
)Diluted loss per common share

$
(12.32
)

(.05
)


See
accompanying Notes to Condensed Consolidated Financial Statements.

2

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FOREST OIL CORPORATION        CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY    
(Unaudited)

Common Stock





Accumulated
Other
Comprehensive
IncomeCapital
Surplus

Accumulated
Deficit

Total
Shareholders'
EquityShares

Amount(In Thousands)Balances at December 31, 2008


97,040

$
9,704


2,354,903


(729,293
)

37,598


1,672,912Exercise of stock options


1





11








11Employee stock purchase plan


40


4


443








447Restricted stock issued, net of cancellations


(2
)













Amortization of stock-based compensation








6,449








6,449Restricted stock redeemed and other


(5
)

(1
)

(90
)







(91
)Comprehensive loss:Net loss











(1,177,773
)




(1,177,773
)Unfunded postretirement benefits, net of tax














36


36Foreign currency translation














(12,826
)

(12,826
)Total comprehensive loss

















(1,190,563
)Balances at March 31, 2009


97,074

$
9,707


2,361,716


(1,907,066
)

24,808


489,165


See
accompanying Notes to Condensed Consolidated Financial Statements.

3

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FOREST OIL CORPORATION        CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS        (Unaudited)

Three Months Ended
March 31,2009

2008(In Thousands)Operating activities:Net loss

$
(1,177,773
)

(4,732
)Adjustments to reconcile net loss to net cash provided by operating activities:Depreciation and depletion


104,552


115,567Accretion of asset retirement obligations


2,038


1,784Stock-based compensation expense


3,947


3,857Unrealized (gains) losses on derivative instruments, net


(67,539
)

142,213Ceiling test write-down of oil and gas properties


1,575,843


Deferred income tax


(291,615
)

(2,332
)Unrealized foreign currency exchange losses, net


3,539


2,775Unrealized losses on other investments, net


2,327


7,091Other, net


1,187


(1,024
)Changes in operating assets and liabilities:Accounts receivable


43,280


(17,665
)Other current assets


10,136


(5,581
)Accounts payable and accrued liabilities


(89,982
)

(47,955
)Accrued interest and other current liabilities


28,426


13,074Net cash provided by operating activities


148,366


207,072Investing activities:Capital expenditures for property and equipment:Exploration, development, and acquisition costs


(301,329
)

(257,650
)Other fixed assets


(21,840
)

(6,428
)Proceeds from sales of assets


6,292


466Other, net





5Net cash used by investing activities


(316,877
)

(263,607
)Financing activities:Proceeds from bank borrowings


430,856


383,590Repayments of bank borrowings


(799,484
)

(340,622
)Issuance of 81/2% senior notes, net of issuance costs


559,767


Proceeds from the exercise of options and from employee stock purchase plan


458


4,924Change in bank overdrafts


(21,752
)

1,611Other, net


(2,663
)

(644
)Net cash provided by financing activities


167,182


48,859Effect of exchange rate changes on cash


(20
)

(90
)Net decrease in cash and cash equivalents


(1,349
)

(7,766
)Cash and cash equivalents at beginning of period


2,205


9,685Cash and cash equivalents at end of period

$
856


1,919Cash paid during the period for:Interest

$
6,100


5,222Income taxes


1,930


44


See accompanying Notes to Condensed Consolidated Financial Statements.

4

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Table of Contents

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 March 31, 2009, the results of its operations for the three months ended March 31, 2009 and 2008, and its cash flows for the three months ended March 31, 2009 and 2008.
Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for liquids (oil, condensate, and natural gas liquids) and natural
gas and other factors.

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

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

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

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

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

Earnings per Share

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number
of common shares outstanding during each period. Under the treasury stock method, diluted earnings (loss) per share is computed by adjusting the weighted average number of common shares outstanding
for the dilutive effect, if any, of stock options, unvested restricted stock grants, and unvested phantom stock units.

In
June 2008, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position ("FSP") No. EITF 03-6-1,Determining
Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities("FSP EITF 03-6-1"), which addressed whether
instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing basic earnings per
share under the two-class method described in Statement of Financial Accounting Standards ("SFAS") No. 128,Earnings per Share. FSP
EITF 03-6-1 was effective for financial statements issued for fiscal years

5

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

beginning
after December 15, 2008 and interim periods within those years. Accordingly, Forest adopted this pronouncement as of January 1, 2009. All prior period earnings per share data
presented have been adjusted retrospectively to conform with the provisions of this pronouncement.

Restricted
stock issued under Forest's stock incentive plans has the right to receive non-forfeitable cash dividends, participating on an equal basis with common stock.
Phantom stock units issued to directors under Forest's stock incentive plans also have the right to receive non-forfeitable cash dividends, participating on an equal basis with common
stock, while phantom stock units issued to employees do not participate in dividends. Stock options issued under Forest's stock incentive plans do not participate in dividends. Therefore, restricted
stock and phantom stock units issued to directors are participating securities and earnings must now be allocated to both common stock and these participating securities in the basic earnings per
share calculation. However, these participating securities do not have a contractual obligation to share in Forest's losses. Therefore, in periods of net loss, none of the loss is allocated to these
participating securities. Since Forest had a net loss for the three months ended March 31, 2009 and 2008, the adoption of FSP EITF 03-6-1 had no impact on its
basic earnings per share calculations for those periods. In periods of net earnings, however, basic earnings per share calculated under the two-class method will likely be lower than it
would had it been prior to the adoption of FSP EITF 03-6-1.

Stock
options, unvested restricted stock grants, and unvested phantom stock units were not included in the calculation of diluted loss per share for the three months ended
March 31, 2009 and 2008 as their inclusion would have an antidilutive effect.

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

Three Months Ended
March 31,2009

2008(In Thousands, Except
Per Share Amounts)Net loss

$
(1,177,773
)

(4,732
)Weighted average common shares outstanding during the period


95,571


87,294Add dilutive effects of stock options, unvested restricted stock grants, and unvested phantom stock units





Weighted average common shares outstanding, including the effects of dilutive securities


95,571


87,294Basic loss per common share

$
(12.32
)

(.05
)Diluted loss per common share

$
(12.32
)

(.05
)


6

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

Comprehensive Earnings (Loss)

Comprehensive earnings (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other
comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity
instead of net earnings (loss). Items included in Forest's other comprehensive income (loss) for the three months ended March 31, 2009 and 2008 are foreign currency losses related to the
translation of the assets and liabilities of Forest's Canadian operations and changes in unfunded postretirement benefits.

The
components of comprehensive loss are as follows:

Three Months Ended
March 31,2009

2008(In Thousands)Net loss

$
(1,177,773
)

(4,732
)Other comprehensive income (loss):Foreign currency translation losses


(12,826
)

(14,290
)Unfunded postretirement benefits, net of tax


36


Total comprehensive loss

$
(1,190,563
)

(19,022
)


(3) STOCK-BASED COMPENSATION

The table below sets forth total stock-based compensation recorded during the three months ended March 31, 2009 and 2008 under the provisions of SFAS No. 123 (Revised), Share-Based Payment

7

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) STOCK-BASED COMPENSATION (Continued)

("SFAS 123(R)"),
and the remaining unamortized amounts and the weighted average amortization period remaining as of March 31, 2009.

Stock
Options

Restricted
Stock

Phantom
Stock Units

Total(1)(In Thousands)Three months ended March 31, 2009:Total stock-based compensation costs

$
277


5,984


(76
)

6,185Less: stock-based compensation costs capitalized


(125
)

(2,346
)

45


(2,426
)Stock-based compensation costs expensed

$
152


3,638


(31
)

3,759Unamortized stock-based compensation costs as of March 31, 2009

$
2,080


40,999


1,254
(2)

44,333Weighted average amortization period remaining


1.5 years


1.9 years


1.9 years


1.9 yearsThree months ended March 31, 2008:Total stock-based compensation costs

$
835


4,436


653


5,924Less: stock-based compensation costs capitalized


(347
)

(1,453
)

(393
)

(2,193
)Stock-based compensation costs expensed

$
488


2,983


260


3,731


---

Stock Options

The following table summarizes stock option activity in the Company's stock-based compensation plans for the three months ended
March 31, 2009.

Number of
Shares

Weighted
Average Exercise
Price

Aggregate
Intrinsic Value
(In Thousands)(1)

Number of
Shares
ExercisableOutstanding at January 1, 2009


2,097,267

$
21.13

$
376


1,898,316Granted


Exercised


(1,115
)

10.01


4Cancelled


(51,391
)

18.53Outstanding at March 31, 2009


2,044,761


21.20





1,859,552


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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) STOCK-BASED COMPENSATION (Continued)

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 three months ended March 31, 2009.

Restricted Stock

Phantom Stock UnitsNumber of
Shares

Weighted
Average Grant
Date Fair Value

Number of
Shares

Weighted
Average Grant
Date Fair ValueUnvested at January 1, 2009


1,490,795

$
52.31


163,954

$
51.10Awarded


500


17.21


9,500


14.83Vested


(16,200
)

48.54


(1,500
)

17.51Forfeited


(2,150
)

50.65


(16,575
)

48.33Unvested at March 31, 2009


1,472,945


52.34


155,379


49.50


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.

(4) DEBT

Components of debt are as follows:

March 31, 2009

December 31, 2008Principal

Unamortized
Premium
(Discount)

Other(2)

Total

Principal

Unamortized
Premium
(Discount)

Other(2)

Total(In Thousands)U.S. Credit Facility

$
800,000








800,000


1,190,000








1,190,000Canadian Credit Facility


112,578








112,578


94,415








94,4158% Senior Notes due 2011


285,000


3,552


2,269


290,821


285,000


3,875


2,475


291,3507% Senior Subordinated Notes due 2013


1,112


(23
)




1,089


1,112


(25
)




1,08781/2% Senior Notes due 2014(1)


600,000


(28,414
)




571,586











73/4% Senior Notes due 2014


150,000


(1,214
)

9,053


157,839


150,000


(1,273
)

9,492


158,21971/4% Senior Notes due 2019


1,000,000


576





1,000,576


1,000,000


590





1,000,590Total debt

$
2,948,690


(25,523
)

11,322


2,934,489


2,720,527


3,167


11,967


2,735,661


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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(4) DEBT (Continued)

Bank Credit Facilities

On March 16, 2009, Forest entered into the Second Amendment (the "Second Amendment") to its second amended and restated combined
credit agreements dated as of June 6, 2007 that amended certain definitions and covenants of the credit agreements, including the total debt outstanding-to-EBITDA ratio.
The effective date of the Second Amendment is March 16, 2009. The second amended and restated combined credit agreements consist of a $1.65 billion U.S. credit facility (the "U.S.
Facility") with a syndicate of banks led by JPMorgan Chase Bank, N.A., and a $150 million Canadian credit facility (the "Canadian Facility," and together with the U.S. Facility, the "Credit
Facilities") with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Credit Facilities will mature in June 2012.

Forest's
availability under the Credit Facilities is governed by a borrowing base (the "Global Borrowing Base"). As a result of issuing $600 million of 81/2% senior
notes due 2014 in February 2009, Forest's borrowing base was lowered from $1.8 billion to $1.62 billion effective February 17, 2009. As a result of the adjustment to the Global
Borrowing Base, Forest reallocated amounts under the U.S. Facility and Canadian Facility and currently has allocated $1.47 billion to the U.S. Facility and $150 million to the Canadian
Facility. On March 16, 2009, Forest announced that its bank group reaffirmed Forest's $1.62 billion Global Borrowing Base and $1.8 billion nominal amount related to the Credit
Facilities. The next redetermination of the borrowing base is scheduled to be in the fourth quarter of 2009.

At
March 31, 2009, there were outstanding borrowings of $800.0 million under the U.S. Facility at a weighted average interest rate of 1.8%, and there were outstanding
borrowings of $112.6 million under the Canadian Facility at a weighted average interest rate of 2.1%. The Company also had used the Credit Facilities for $2.7 million in letters of
credit, leaving an unused borrowing amount under the Credit Facilities of $704.7 million at March 31, 2009.

81/2% Senior Notes Due 2014

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

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

10

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(5) OIL AND GAS PROPERTIES

Full Cost Method of Accounting

The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country
in which the Company has operations. During the periods presented, the Company's primary oil and gas operations were conducted in the United States and Canada. All costs incurred in the acquisition,
exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and
the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. During the three months ended March 31, 2009 and 2008, Forest
capitalized $10.4 million and $12.1 million of general and administrative costs (including stock-based compensation), respectively. Interest costs related to significant unproved
properties that are under development are also capitalized to oil and gas properties. During the three months ended March 31, 2009 and 2008, the Company capitalized $3.4 million and
$5.2 million, respectively, of interest costs attributed to unproved properties.

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

Pursuant
to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within each separate cost center. The ceiling test provides
that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated
production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at
a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs
being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the
sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. As a result of this limitation on capitalized costs, the
accompanying financial statements included a provision for a ceiling test write-down of oil and gas property costs for the three months ended March 31, 2009 of $1.377 billion
in the United States and $199.0 million in Canada.

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.

11

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(5) OIL AND GAS PROPERTIES (Continued)

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.

Acquisitions

Texas Properties Acquisition

On September 30, 2008, Forest acquired producing oil and natural gas properties located in its Greater Buffalo Wallow and
Ark-La-Tex core areas from Cordillera Texas, L.P. Forest paid approximately $570 million in cash, subject to customary post-closing adjustments to
reflect an economic effective date of July 1, 2008, and issued 7.25 million shares of Forest's common stock, valued at approximately $360 million (based on a September 30,
2008 closing price), to the seller for the acquired assets. Forest funded the cash component of the purchase price primarily using advances under its credit facilities.

Ark-La-Tex Properties Acquisition

On May 2, 2008, Forest acquired producing oil and natural gas properties located primarily in its core
Ark-La-Tex region in East Texas and North Louisiana. Forest paid approximately $284 million, as adjusted to reflect an economic effective date of April 1, 2008,
for the assets using funds advanced under its credit facilities.

(6) ASSET RETIREMENT OBLIGATIONS

Forest records estimated future asset retirement obligations pursuant to the provisions of SFAS 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.

12

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(6) ASSET RETIREMENT OBLIGATIONS (Continued)

The following table summarizes the activity for Forest's asset retirement obligations for the three
months ended March 31, 2009 and 2008.

Three Months
Ended March 31,2009

2008(In Thousands)Asset retirement obligations at beginning of period

$
96,991


90,505Accretion expense


2,038


1,784Liabilities incurred


1,313


2,417Liabilities settled


(880
)

(843
)Disposition of properties


(607
)

Liabilities assumed





319Revisions of estimated liabilities


1,172


(1,921
)Impact of foreign currency exchange rate


(383
)

(571
)Asset retirement obligations at end of period


99,644


91,690Less: current asset retirement obligations


(3,477
)

(3,308
)Long-term asset retirement obligations

$
96,167


88,382


(7) FAIR VALUE MEASUREMENTS

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements("SFAS 157"). This statement clarifies the
definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The Company adopted the provisions of SFAS 157 as of
January 1, 2008 for all financial and nonfinancial assets and liabilities recognized or disclosed at fair value on a recurring basis. The Company has also adopted SFAS 157 as it relates
to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g. those measured at fair value in a business combination, the initial recognition of
asset retirement obligations, and impairments of goodwill and other long-lived assets) as of January 1, 2009 pursuant to the provisions of FASB Staff Position No.
FAS 157-2,Effective Date of FASB Statement No. 157. The adoption of SFAS 157 did not materially impact the Company's
financial position, results of operations, or cash flow.

SFAS 157
establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as
unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly
observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As
of March 31, 2009, the Company held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including: (i) the
Company's commodity and interest rate derivative instruments and (ii) other investments, comprised of a zero coupon senior subordinated note due from Pacific Energy Resources, Ltd.
("PERL") in 2014 at a principal amount at stated maturity of $60.8 million (the "PERL Note") and 10 million shares of PERL common stock (the "PERL Shares").

13

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(7) FAIR VALUE MEASUREMENTS (Continued)

The
Company used the income approach in determining the fair value of its derivative instruments, utilizing present value techniques for valuing its swaps and basis swaps and
option-pricing models for valuing its collars. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of
published interest rates and credit spreads. All of these inputs are observable, either directly or indirectly; therefore, the Company's derivative instruments are included within the Level 2
fair value hierarchy.

The
Company used the income approach in determining the fair value of the PERL Shares and Note, which are included within the Level 3 fair value hierarchy. Because
PERL's common shares were suspended from trading in March 2009 for failure to meet the continued stock exchange listing requirements, there is no active market for them and they can no
longer be valued within the Level 1 fair value hierarchy. The Company used its own assumptions about the assumptions that market participants would use regarding future cash flows and
risk-adjusted discount rates in valuing the PERL Shares and Note. PERL filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in March 2009. The
bankruptcy proceedings are still at a very early stage; however, PERL has indicated that the value of its assets is less than the amount of PERL's senior unsubordinated debt. Based on
these facts and circumstances, the Company estimates the fair value of the PERL Shares and Note to be zero.

The
Company's assets and liabilities measured at fair value on a recurring basis at March 31, 2009, were as follows:

Description

Using
Significant Other
Observable Inputs
(Level 2)

Using
Significant
Unobservable Inputs
(Level 3)

Total(In Thousands)Assets:Derivative instruments

$
250,726





250,726Equity securities








Debt securities








Liabilities:Derivative instruments


14,098





14,098


14

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(7) FAIR VALUE MEASUREMENTS (Continued)

The following table presents a reconciliation of the beginning and ending balances of the Company's assets measured at fair value on a recurring
basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2009 and 2008.

Three Months Ended
March 31, 2009

Three
Months
Ended
March 31,
2008Equity
Securities

Debt
Securities

Debt
Securities(In Thousands)Balance at beginning of period

$



1,670


15,023Total gains or (losses) (realized/unrealized):Included in earnings


(657
)

(1,670
)

1,046Included in other comprehensive income








Purchases, sales, issuances, and settlements (net)








Transfers in and/or out of Level 3


657





Balance at end of period

$






16,069The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating
to assets still held at end of period

$
(657
)

(1,670
)

238


Gains and losses (realized and unrealized) included in earnings related to the Company's assets measured at fair value on a recurring basis using
significant unobservable inputs (Level 3) for the three months ended March 31, 2009 and 2008 are reported in the Condensed Consolidated Statements of Operations as follows:

Three Months Ended
March 31, 2009

Three Months Ended
March 31, 2008Equity Securities

Debt Securities

Debt SecuritiesUnrealized
Losses on
Other Investments,
Net

Unrealized
Losses on
Other Investments,
Net

Unrealized
Losses on
Other Investments,
Net

Other Expense,
Net(1)(In Thousands)Total losses or (gains) included in earnings for the period

$
657


1,670


(238
)

(808
)Change in unrealized losses or (gains) relating to assets still held at end of period

$
657


1,670


(238
)




---

15

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(7) FAIR VALUE MEASUREMENTS (Continued)

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

March 31, 2009

December 31, 2008Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value(In Thousands)Cash

$
856


856


2,205


2,205Accounts receivable


113,030


113,030


157,226


157,226Other investments








2,327


2,327Derivative instruments, net


236,628


236,628


170,111


170,111Credit facilities


912,578


912,578


1,284,415


1,284,4158% senior notes due 2011


290,821


273,600


291,350


256,5007% senior subordinated notes due 2013


1,089


1,001


1,087


91281/2% senior notes due 2014


571,586


558,000





73/4% senior notes due 2014


157,839


133,500


158,219


123,00071/4% senior notes due 2019


1,000,576


790,000


1,000,590


780,000


The Company used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash
equivalents and accounts receivable approximated their fair value due to the short maturity of these instruments. The carrying amount of the Company's credit facilities approximated fair value,
because the interest rates on the credit facilities are variable. The fair values of the Company's senior notes and senior subordinated notes were estimated based on quoted market prices, if
available, or quoted market prices of comparable instruments. The fair values of the Company's derivative instruments and other investments are discussed above.

(8) DERIVATIVE INSTRUMENTS

Commodity Derivatives

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, the Company has elected not to designate its derivatives as hedging instruments under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities("SFAS 133"). As such, the Company recognizes all changes in fair value of its
derivative instruments in earnings rather than deferring such amounts in accumulated other comprehensive income included in shareholders' equity, as would be done if the derivatives were designated as
hedging instruments under SFAS 133 and cash flow hedge accounting were utilized.

In
March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activitiesan amendment of FASB Statement
No. 133("SFAS 161"). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair
value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement was
effective for fiscal

16

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

years
and interim periods beginning after November 15, 2008. Accordingly, Forest has adopted this pronouncement as of January 1, 2009.

The
table below sets forth Forest's outstanding commodity swaps and collars as of March 31, 2009.

Natural Gas (NYMEX HH)

Oil (NYMEX WTI)Bbtu
Per Day

Weighted Average
Hedged Price
per MMBtu

Barrels
Per Day

Weighted Average
Hedged Price
per BblSwaps:April 2009 - October 2009


210
(1)
$
7.33


4,500

$
69.01November 2009 - December 2009


160
(1)

8.24


4,500


69.01Calendar 2010


150


6.36


1,500


72.95Costless Collars:April 2009 - December 2009


40

$
7.31/9.76
(2)



$



---

Forest also uses basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the
index price at which the natural gas production is sold. The table below sets forth Forest's outstanding basis swaps as of March 31, 2009. Subsequent to
March 31, 2009, through April 30, 2009, Forest entered into additional basis swaps covering 40 Bbtu per day for Calendar 2010 at a weighted average hedged price differential of $(.44)
for the NGPL TXOK index.

Index

Bbtu Per Day

Weighted Average
Hedged Price
Differential
per MMBtuApril 2009 - December 2009

AECO


25

$
(.65
)April 2009 - December 2009

Centerpoint


30


(.95
)April 2009 - December 2009

Houston Ship Channel


50


(.33
)April 2009 - December 2009

Mid Continent


60


(1.04
)April 2009 - December 2009

NGPL TXOK


40


(.53
)Calendar 2010

Centerpoint


30


(.95
)Calendar 2010

Mid Continent


60


(1.04
)


17

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

Interest Rate Derivatives

Forest periodically enters into interest rate derivative agreements in an attempt to normalize the mix of fixed and floating interest
rates within its debt portfolio. In June 2008, the Company terminated all of its interest rate swaps outstanding. In February 2009, the Company entered into a fixed to floating interest rate swap as
set forth in the table below.

Swap Term

Notional
Amount
(In Thousands)

Floating Rate

Fixed
RateFebruary 2009 - February 2014

$
100,000

1 month LIBOR + 6.00%


8.50
%


In addition to the interest rate swap, during the three months ended March 31, 2009, Forest entered into certain interest rate swaptions,
which enable the counterparties to exercise options to enter into interest rate swaps with Forest. Forest received premiums on these swaptions. The interest rate swaps underlying the swaptions also
exchange the 8.5% fixed interest rate on a portion of the 81/2% Notes for a variable rate over the term of the 81/2% Notes. Forest entered into these interest rate
swaptions as its target interest rates are currently not attainable in the interest rate swap market. The table below sets forth Forest's outstanding interest rate swaptions as of March 31,
2009. Subsequent to March 31, 2009, through April 30, 2009, the counterparties have not exercised their options.

Option Term

Swap Term

Premiums
Received
(In Thousands)

Notional
Amount
(In Thousands)

Weighted Average
Floating Rate

Weighted
Average
Fixed
RateMarch 2009 - June 2009

June 2009 - February 2014

$
1,322

$
200,000

1 month LIBOR + 5.85%


8.50
%


Subsequent to March 31, 2009, through April 30, 2009, Forest entered into certain additional interest rate swaptions as set forth in
the table below.

Option Term

Swap Term

Premiums
Received
(In Thousands)

Notional
Amount
(In Thousands)

Weighted Average
Floating Rate

Weighted
Average
Fixed
RateApril 2009 - July 2009

July 2009 - February 2014

$
1,065

$
225,000

1 month LIBOR + 5.88%


8.50
%


18

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

Fair Value and Gains and Losses

The table below summarizes the location and fair value amounts of Forest's derivative instruments reported in the Condensed
Consolidated Balance Sheets as of the period indicated. These derivative instruments are not designated as hedging instruments under SFAS 133. For financial reporting purposes, Forest does not
offset asset and liability fair value amounts recognized for derivative instruments with the same counterparty under its master netting arrangements. See Note 7 to the Condensed Consolidated
Financial Statements for more information on our derivative instruments.

March 31, 2009

December 31, 2008(In Thousands)Assets:Commodity derivatives:Current assets: derivative instruments

$
230,567


169,387Derivative instruments


18,879


4,608Interest rate derivatives:Current assets: derivative instruments


286


Derivative instruments


994


Total assets


250,726


173,995Liabilities:Commodity derivatives:Current liabilities: derivative instruments


7,460


1,284Derivative instruments


6,092


2,600Interest rate derivatives:Current liabilities: derivative instruments


546


Total liabilities


14,098


3,884Net derivative fair value

$
236,628


170,111


19

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

The table below summarizes the location and amount of derivative instrument gains and losses
reported in the Condensed Consolidated Statements of Operations for the periods indicated. These derivative instruments are not designated as hedging instruments under SFAS 133, as such the
gains and losses are included in Other income and expense in the Condensed Consolidated Statements of Operations.

Three Months Ended
March 31,2009

2008(In Thousands)Commodity derivatives:Realized (gains) losses

$
(71,265
)

3,379Unrealized (gains) losses


(65,784
)

137,430Interest rate derivatives:Realized (gains) losses


(524
)

284Unrealized (gains) losses


(1,755
)

4,783Realized and unrealized (gains) losses on derivative instruments, net

$
(139,328
)

145,876


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

Credit Risk

Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. ("ISDA")
Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes, with each of
its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties' requirements and the specific types of derivatives to be
traded. Forest's derivative counterparties are also lenders or affiliates of lenders under its Credit Facilities. The Credit Facilities provide that any security granted by Forest under the Credit
Facilities shall also extend to and be available to those lenders that are counterparties to derivative transactions with Forest. The ISDA Master Agreements and Schedules do not contain any terms
requiring further collateral than is required under the Credit Facilities. The Credit Facilities are collateralized by a portion of the Company's assets. The Company is required to mortgage and grant
a security interest in the greater of (i) 75% of the present value of its consolidated proved oil and gas properties or (ii) 1.875 multiplied by the allocated U.S. borrowing base. The
Company is also required to and has pledged the stock of several subsidiaries to the lenders to secure the Credit Facilities. Under certain circumstances, the Company could be obligated to pledge
additional assets as collateral. If Forest's corporate credit ratings assigned by Moody's and S&P improve and meet pre-established levels, the collateral requirements would cease to apply
and, at the Company's request, the banks would

20

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(8) DERIVATIVE INSTRUMENTS (Continued)

release
their liens on and security interests in the Company's properties. In addition to these collateral requirements, one of the Company's subsidiaries, Forest Oil Permian Corporation, is a
subsidiary guarantor of the Credit Facilities.

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

Forest's
derivative counterparties are all financial institutions that are engaged in similar activities and have similar economic characteristics that, in general, could cause their
ability to meet contractual obligations to be similarly affected by changes in economic or other conditions. Forest does not require the posting of collateral for its benefit under its derivative
agreements. However, Forest's ISDA Master Agreements contain netting provisions whereby if on any date amounts would otherwise be payable by
each party to the other, then on such date the party that owes the larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party's
obligations. These provisions apply to all derivative transactions with the particular counterparty. If all counterparties failed, we would be exposed to a risk of loss equal to this net amount owed
to us, the fair value of which is $237.9 million at March 31, 2009. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification
periods, of the net obligations due to it under the derivative agreement. At March 31, 2009, Forest owed a net derivative liability to only one counterparty, the fair value of which is
$1.2 million.

21

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(9) INCOME TAXES

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

Three Months Ended
March 31,2009

2008(In Thousands)Federal income tax at 35% of loss before income taxes

$
(513,842
)

(2,480
)Change in valuation allowance for deferred tax assets


215,836


State income taxes, net of federal income tax benefits


(14,244
)

(320
)Effect of differing tax rates in Canada


12,338


(990
)Effect of federal, state, and foreign tax on permanent items


3,119


725Adjustments for statutory rate reductions and other


6,446


711Total income tax

$
(290,347
)

(2,354
)


In
assessing the need for a valuation allowance on the Company's deferred tax assets, all available evidence, both negative and positive, was considered in determining whether it is more
likely than not that some portion or all of the deferred tax assets will be realized. Based on this assessment, Forest recorded an additional valuation allowance of $215.3 million against its
U.S. deferred tax assets as of March 31, 2009. In addition, the effective income tax rate was adjusted for the effect of valuation allowances provided for deferred tax assets and capital losses
in Canada of approximately $.5 million.

(10) GEOGRAPHICAL SEGMENTS

Segment information has been prepared in accordance with SFAS No. 131,Disclosures About Segments of an Enterprise and Related
Information. At March 31, 2009, Forest conducted operations in one industry segment, that being the oil and gas exploration and production industry, and had three
reportable geographical business segments: United States, Canada, and International. Forest's remaining activities were not significant and therefore were not reported as a separate segment, but have
been included as a reconciling item in the information below. The segments were determined

22

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(10) GEOGRAPHICAL SEGMENTS (Continued)

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 OperationsThree Months Ended March 31, 2009United States

Canada

International

Total Company(In Thousands)Revenue

$
166,352


28,307





194,659Expenses:








Lease operating expenses


34,702


6,529





41,231Production and property taxes


10,944


751





11,695Transportation and processing costs


3,039


2,205





5,244Depletion


86,491


15,678





102,169Ceiling test write-down of oil and gas properties


1,376,822


199,021





1,575,843Accretion of asset retirement obligations


1,772


243


23


2,038Loss from operations

$
(1,347,418
)

(196,120
)

(23
)

(1,543,561
)Capital expenditures(1)

$
225,860


25,976


965


252,801Goodwill

$
239,420


13,738





253,158


---

A reconciliation of segment loss from operations to consolidated loss before income taxes is as follows:

Three Months Ended
March 31, 2009(In Thousands)Loss from operations for reportable segments

$
(1,543,561
)Marketing, processing, and other


8General and administrative expense (including stock-based compensation)


(16,085
)Administrative asset depreciation


(2,383
)Interest expense


(36,545
)Realized and unrealized gains on derivative instruments, net


139,328Unrealized foreign currency exchange losses, net


(3,539
)Unrealized losses on other investments, net


(2,327
)Other expense, net


(3,016
)Loss before income taxes

$
(1,468,120
)


23

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(10) GEOGRAPHICAL SEGMENTS (Continued)



Oil and Gas OperationsThree Months Ended March 31, 2008United States

Canada

International

Total Company(In Thousands)Revenue

$
315,496


61,091





376,587Expenses:Lease operating expenses


28,934


8,631





37,565Production and property taxes


19,174


877





20,051Transportation and processing costs


2,432


2,493





4,925Depletion


91,859


22,089





113,948Accretion of asset retirement obligations


1,475


288


21


1,784Earnings (loss) from operations

$
171,622


26,713


(21
)

198,314Capital expenditures(1)

$
195,739


71,175


905


267,819Goodwill

$
237,578


16,881





254,459


---

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

Three Months Ended
March 31, 2008(In Thousands)Earnings (loss) from operations for reportable segments

$
198,314Marketing, processing, and other


(57
)General and administrative expense (including stock-based compensation)


(19,288
)Administrative asset depreciation


(1,619
)Interest expense


(27,857
)Realized and unrealized losses on derivative instruments, net


(145,876
)Unrealized foreign currency exchange losses, net


(2,775
)Unrealized losses on other investments, net


(7,091
)Other expense, net


(837
)Loss before income taxes

$
(7,086
)


24

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(10) GEOGRAPHICAL SEGMENTS (Continued)

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

Total AssetsMarch 31, 2009

December 31, 2008(In Thousands)United States

$
3,455,316


4,476,489Canada


476,440


726,895International


79,578


79,414Total assets

$
4,011,334


5,282,798




Long-Lived AssetsMarch 31, 2009

December 31, 2008(In Thousands)United States

$
2,771,602


3,998,129Canada


472,385


691,009International


78,618


77,672Total long-lived assets

$
3,322,605


4,766,810


25

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

CONDENSED CONSOLIDATING BALANCE SHEETS  (Unaudited)  (In Thousands)

March 31, 2009

December 31, 2008Parent
Company

Guarantor
Subsidiary

Combined
Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Parent
Company

Guarantor
Subsidiary

Combined
Non-Guarantor
Subsidiaries

Eliminations

ConsolidatedASSETSCurrent assets:Cash and cash equivalents

$
465


21


370





856


1,226


74


905





2,205Accounts receivable


59,947


18,565


35,237


(719
)

113,030


106,941


22,003


28,584


(302
)

157,226Other current assets


358,908


819


8,392





368,119


304,424


471


8,723





313,618Total current assets


419,320


19,405


43,999


(719
)

482,005


412,591


22,548


38,212


(302
)

473,049Property and equipment, at cost


7,512,416


1,311,247


1,446,596





10,270,259


7,327,978


1,259,337


1,465,891





10,053,206Less accumulated depreciation, depletion, and amortization


5,372,315


964,436


864,061





7,200,812


4,145,061


727,858


667,123





5,540,042Net property and equipment


2,140,101


346,811


582,535





3,069,447


3,182,917


531,479


798,768





4,513,164Investment in subsidiaries


190,368








(190,368
)




577,405








(577,405
)

Note receivable from subsidiary


93,052








(93,052
)




93,052








(93,052
)

Deferred income taxes


187,108








(50,532
)

136,576














Goodwill


216,460


22,960


13,738





253,158


216,460


22,960


14,226





253,646Due from (to) parent and subsidiaries


483,281


66,293


(549,574
)







391,074


141,656


(532,730
)




Other assets


67,989


5


2,154





70,148


40,607


5


2,327





42,939$
3,797,679


455,474


92,852


(334,671
)

4,011,334


4,914,106


718,648


320,803


(670,759
)

5,282,798LIABILITIES AND SHAREHOLDERS' EQUITYCurrent liabilities:Accounts payable and accrued liabilities

$
206,173


15,424


42,517


(719
)

263,395


338,754


27,631


58,858


(302
)

424,941Other current liabilities


143,893


1,040


5,650





150,583


88,064


1,165


7,241





96,470Total current liabilities


350,066


16,464


48,167


(719
)

413,978


426,818


28,796


66,099


(302
)

521,411Long-term debt


2,821,911





112,578





2,934,489


2,641,246





94,415





2,735,661Note payable to parent








93,052


(93,052
)










93,052


(93,052
)

Other liabilities


136,537


3,383


33,782





173,702


128,017


3,397


35,813





167,227Deferred income taxes





25,478


25,054


(50,532
)




45,113


61,383


79,091





185,587Total liabilities


3,308,514


45,325


312,633


(144,303
)

3,522,169


3,241,194


93,576


368,470


(93,354
)

3,609,886Shareholders' equity


489,165


410,149


(219,781
)

(190,368
)

489,165


1,672,912


625,072


(47,667
)

(577,405
)

1,672,912$
3,797,679


455,474


92,852


(334,671
)

4,011,334


4,914,106


718,648


320,803


(670,759
)

5,282,798


26

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS  (Unaudited)  (In Thousands)

Three Months Ended March 31,2009

2008Parent
Company

Guarantor
Subsidiary

Combined
Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Parent
Company

Guarantor
Subsidiary

Combined
Non-Guarantor
Subsidiaries

Eliminations

ConsolidatedRevenues

$
133,142


32,521


29,004





194,667


254,051


25,880


94,052


2,547


376,530Operating expenses:Lease operating expenses


28,925


5,556


6,743


7


41,231


24,143


3,147


10,266


9


37,565Other direct operating costs


13,153


1,474


2,312





16,939


18,041


1,856


5,079





24,976General and administrative (including stock-based compensation)


13,312


715


2,058





16,085


16,876


6


2,406





19,288Depreciation and depletion


71,516


18,011


16,581


(1,556
)

104,552


76,353


5,435


33,782


(3
)

115,567Ceiling test write-down of oil and gas properties


1,155,777


218,567


201,499





1,575,843














Other operating expenses


1,692


81


265





2,038


1,409


41


334





1,784Total operating expenses


1,284,375


244,404


229,458


(1,549
)

1,756,688


136,822


10,485


51,867


6


199,180Earnings (loss) from operations


(1,151,233
)

(211,883
)

(200,454
)

1,549


(1,562,021
)

117,229


15,395


42,185


2,541


177,350Equity earnings in subsidiaries


(310,643
)







310,643





28,879








(28,879
)

Other income and expense:Interest expense


31,667


2,303


5,551


(2,976
)

36,545


24,192





7,985


(4,320
)

27,857Realized and unrealized (gains) losses on derivative instruments, net


(113,095
)

(25,723
)

(510
)




(139,328
)

139,153


24,051


(17,328
)




145,876Other expense (income), net


860


(60
)

4,586


3,496


8,882


3,449


(34
)

1,775


5,513


10,703Total other income and expense


(80,568
)

(23,480
)

9,627


520


(93,901
)

166,794


24,017


(7,568
)

1,193


184,436Earnings (loss) before income taxes


(1,381,308
)

(188,403
)

(210,081
)

311,672


(1,468,120
)

(20,686
)

(8,622
)

49,753


(27,531
)

(7,086
)Income tax


(203,535
)

(35,928
)

(50,884
)




(290,347
)

(15,954
)

(3,177
)

16,777





(2,354
)Net earnings (loss)

$
(1,177,773
)

(152,475
)

(159,197
)

311,672


(1,177,773
)

(4,732
)

(5,445
)

32,976


(27,531
)

(4,732
)


27

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS  (Unaudited)  (In Thousands)

Three Months Ended March 31,2009

2008Parent
Company

Guarantor
Subsidiary

Combined
Non-Guarantor
Subsidiaries

Consolidated

Parent
Company

Guarantor
Subsidiary

Combined
Non-Guarantor
Subsidiaries

ConsolidatedOperating activities:Net earnings (loss)

$
(867,130
)

(152,475
)

(158,168
)

(1,177,773
)

(32,263
)

(5,445
)

32,976


(4,732
)Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities:Depreciation and depletion


71,516


18,011


15,025


104,552


76,353


5,435


33,779


115,567Unrealized (gains) losses on derivative instruments, net


(54,947
)

(12,347
)

(245
)

(67,539
)

139,974


20,163


(17,924
)

142,213Deferred income tax


(204,803
)

(35,928
)

(50,884
)

(291,615
)

(15,902
)

(3,177
)

16,747


(2,332
)Ceiling test write-down of oil and gas properties


1,155,777


218,567


201,499


1,575,843











Other, net


9,017


81


3,940


13,038


10,894


41


3,548


14,483Changes in operating assets and liabilities:Accounts receivable


46,994


3,438


(7,152
)

43,280


(6,746
)

(1,474
)

(9,445
)

(17,665
)Other current assets


10,465


(348
)

19


10,136


(4,145
)

(99
)

(1,337
)

(5,581
)Accounts payable and accrued liabilities


(71,829
)

(5,014
)

(13,139
)

(89,982
)

(45,586
)

(737
)

(1,632
)

(47,955
)Accrued interest and other current liabilities


30,496


(249
)

(1,821
)

28,426


11,338


(37
)

1,773


13,074Net cash provided (used) by operating activities


125,556


33,736


(10,926
)

148,366


133,917


14,670


58,485


207,072Investing activities:Capital expenditures for property and equipment


(228,685
)

(56,534
)

(37,950
)

(323,169
)

(159,393
)

(6,037
)

(98,648
)

(264,078
)Other, net


96





6,196


6,292


23





448


471Net cash used by investing activities


(228,589
)

(56,534
)

(31,754
)

(316,877
)

(159,370
)

(6,037
)

(98,200
)

(263,607
)Financing activities:Issuance of 81/2% senior notes, net of issuance costs


559,767








559,767











Proceeds from bank borrowings


373,000





57,856


430,856


306,000





77,590


383,590Repayments of bank borrowings


(763,000
)




(36,484
)

(799,484
)

(271,000
)




(69,622
)

(340,622
)Net activity in investments from subsidiaries


(42,729
)

25,262


17,467





(13,027
)

(8,832
)

21,859


Other, net


(24,766
)

(2,517
)

3,326


(23,957
)

3,086


85


2,720


5,891Net cash provided (used) by financing activities


102,272


22,745


42,165


167,182


25,059


(8,747
)

32,547


48,859Effect of exchange rate changes on cash








(20
)

(20
)







(90
)

(90
)Net decrease in cash and cash equivalents


(761
)

(53
)

(535
)

(1,349
)

(394
)

(114
)

(7,258
)

(7,766
)Cash and cash equivalents at beginning of period


1,226


74


905


2,205


1,189


386


8,110


9,685Cash and cash equivalents at end of period

$
465


21


370


856


795


272


852


1,919


28

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(12) RECENT ACCOUNTING PRONOUNCEMENTS

In December 2008, the FASB issued FSP No. FAS 132(R)-1,Employers' Disclosures About Postretirement Benefit Plan Assets("FSP FAS 132(R)-1"), which provides guidance on an employer's disclosures about plan assets of a defined benefit pension or other postretirement benefit plan. FSP
FAS 132(R)-1 states that disclosures concerning plan assets should provide users of financial statements with an understanding of: investment policies and strategies; categories of
plan assets; fair value measurements of plan assets; and significant concentrations of risk. The disclosures required by FSP FAS 132(R)-1 shall be provided for fiscal years ending
after December 15, 2009. The Company is currently evaluating the impact that the adoption of this pronouncement will have on the Company's plan asset disclosures.

In
December 2008, the Securities and Exchange Commission adopted revisions to its oil and gas disclosure requirements that are intended to align them with current practices and changes
in technology. Among other things, the amendments will: replace the single-day year-end pricing assumption with a twelve-month average pricing assumption; permit the disclosure
of probable and possible reserves; allow the use of certain technologies to establish reserves; require the disclosure of the qualifications of the technical person primarily responsible for preparing
the reserves estimates or conducting a reserves audit; require the filing of the independent reserve engineers' summary report; and permit the disclosure of a reserves sensitivity analysis table to
illustrate the impact of different price and/or cost assumptions on reserves. These amendments are effective for registration statements filed on or after January 1, 2010, and for annual
reports on Form 10-K for fiscal years ending on December 31, 2009, with early adoption prohibited. The Company is currently evaluating the impact that the adoption of this
pronouncement will have on the Company's financial position, results of operations, and disclosures.

In
April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial
Instruments("FSP FAS 107-1 and APB 28-1"), which requires the disclosure of the fair value, together with the carrying amount, of
financial instruments, regardless of whether they are recognized at fair value in the statement of financial position, for interim reporting periods of publicly traded companies as well as in annual
financial statements. This pronouncement is effective for interim reporting periods ending after June 15, 2009, with earlier adoption permitted for periods ending after March 15, 2009.
The Company has adopted this pronouncement for the quarter ended March 31, 2009. As this pronouncement requires
only additional disclosures, there was no impact on the Company's financial position or results of operations as a result of the adoption.

In
April 2009, the FASB issued FSP No. FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have
Significantly Decreased and Identifying Transactions That Are Not Orderly("FSP FAS 157-4"), which provides additional guidance for estimating fair value in
accordance with SFAS 157 in certain circumstances. This pronouncement is effective for interim and annual reporting periods ending after June 15, 2009, with earlier adoption permitted
for periods ending after March 15, 2009. An entity that early adopts FSP FAS 107-1 and APB 28-1 must also early adopt FSP FAS 157-4.
Accordingly, the Company adopted this pronouncement for the quarter ended March 31, 2009; however, there was no impact on the Company's financial position or results of operations as a result
of the adoption.

29

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Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(12) RECENT ACCOUNTING PRONOUNCEMENTS (Continued)

In
April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2,Recognition and Presentation of
Other-Than-Temporary Impairments("FSP FAS 115-2 and FAS 124-2"), which amends the existing
other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of
other-than-temporary impairments on debt and equity securities in the financial statements. Other-than-temporary impairment relates to investments in
debt and equity securities for which changes in fair value are not regularly recognized in earnings (such as securities classified as held-to-maturity or
available-for-sale). This pronouncement is effective for interim and annual reporting periods ending after June 15, 2009, with earlier adoption permitted for periods
ending after March 15, 2009. An entity that early adopts FSP FAS 107-1 and APB 28-1 must also early adopt FSP FAS 115-2 and
FAS 124-2. Accordingly, the Company has adopted this pronouncement for the quarter ended March 31, 2009; however, since the Company has no such investments in debt or equity
securities, there was no impact on the Company's financial position or results of operations as a result of the adoption.

30

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Table of Contents

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

OVERVIEW

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

We
currently conduct our operations in three geographical segments and five business units. The geographical segments are: the United States, Canada, and International. The business
units are: Western, Eastern, Southern, Canada, and International. We conduct exploration and development activities in each of our geographical segments; however, substantially all of our estimated
proved reserves and all of our producing properties are located in North America. Our total estimated proved reserves as of December 31, 2008 were approximately 2,668 Bcfe. At
December 31, 2008, approximately 87% of our estimated proved oil and natural gas reserves were in the United States, approximately 11% were in Canada, and approximately 2% were in Italy.
Approximately 75% of our estimated proved reserves were natural gas as of December 31, 2008. See Note 10 to the Condensed Consolidated Financial Statements for additional information
about our geographical segments.

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

First Quarter 2009 Summary

Forest's first quarter 2009 highlights and other significant items were as follows:



31

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Table of Contents



2009 Outlook

Due to the downturn in the global economy as well as the dramatic decrease in oil and natural gas prices, we have significantly reduced
our capital expenditure and drilling budget for 2009 as compared to 2008. Our goal in 2009 will be to keep our full-year exploration and development capital expenditures within our cash
flow from operations, while maintaining our estimated proved reserve base and production, protecting against lease expirations and non-consent penalties, and continuing to focus on cost
control. Due to continuing declines in oil and natural gas prices, this goal may not be achievable.

Our
goal to keep 2009 capital spending within our cash flow from operations is targeted to maintain financial flexibility and sufficient liquidity to maintain our assets and operations
until margins on oil and gas production improve. In order to preserve borrowing capacity and flexibility under our bank credit facilities, in February 2009, we issued $600 million in senior
notes due 2014 and used the net proceeds to pay down borrowings on the facilities. We have a divestiture program with an announced intention to sell certain oil and gas assets outside our core areas.
Due to the current economic conditions, this program has been delayed. We hope to complete these divestitures by the end of 2010, assuming market conditions and property valuations improve, but cannot
predict whether we will be able to complete any asset divestitures. If divestitures are completed, we intend to use the proceeds to reduce debt.

RESULTS OF OPERATIONS

For the first quarter 2009, Forest reported a net loss of $1.2 billion, or a loss of $12.32 per basic share, compared to a net
loss of $4.7 million, or a loss of $.05 per basic share, in the first quarter 2008. The increase in the net loss in the first quarter 2009 compared to the first quarter 2008 was primarily due
to a $1.6 billion non-cash ceiling test write-down recorded in the first quarter 2009 which was caused by the significant decline in spot natural gas prices.
Significantly lower realized oil and gas prices in the first quarter 2009 as compared to the first quarter 2008 also contributed to the decline in net earnings. Discussion of the components of the
changes in our quarterly results follows.

Oil and Gas Production and Revenues

Production volumes, revenues, and weighted average sales prices by product and location for the three months ended March 31,
2009 and 2008 are set forth in the table below.

Three Months Ended March 31,2009

2008Gas

Oil

NGLs

Total

Gas

Oil

NGLs

Total(MMcf)

(MBbls)

(MBbls)

(MMcfe)

(MMcf)

(MBbls)

(MBbls)

(MMcfe)Production volumes:United States


32,120


937


810


42,602


26,358


939


676


36,048Canada


5,468


168


64


6,860


5,817


188


84


7,449Totals


37,588


1,105


874


49,462


32,175


1,127


760


43,497Revenues (in thousands):United States

$
115,605


35,100


15,647


166,352


193,300


89,610


32,586


315,496Canada


20,841


5,660


1,806


28,307


40,127


16,022


4,942


61,091Totals

$
136,446


40,760


17,453


194,659


233,427


105,632


37,528


376,587Average sales price:United States

$
3.60


37.46


19.32


3.90


7.33


95.43


48.20


8.75Canada


3.81


33.69


28.22


4.13


6.90


85.22


58.83


8.20Totals

$
3.63


36.89


19.97


3.94


7.25


93.73


49.38


8.66


32

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Table of Contents

Net
oil and gas production in the first quarter 2009 was 49.5 Bcfe, or an average of 550 MMcfe per day, a 14% increase from 43.5 Bcfe, or an average of 478 MMcfe per day,
in the first quarter 2008. The increase in oil and gas production for the comparable three month periods was due to continued drilling activity and acquisitions of producing oil and gas properties
partially offset by non-core asset dispositions and natural production declines on oil and gas properties.

Oil
and natural gas revenues were $195 million in the first quarter 2009, reflecting a 48% decrease as compared to $377 million in the first quarter 2008. The decrease in
oil and natural gas revenues between the comparable three month periods was primarily due to a 55% decrease in average realized sales prices.

Oil and Gas Production Expense

The table below sets forth the detail of oil and gas production expense for the three months ended March 31, 2009 and 2008.

Three Months
Ended
March 31,2009

2008(In Thousands,
Except
Per Mcfe Data)Production expense:Lease operating expenses

$
41,231


37,565Production and property taxes


11,695


20,051Transportation and processing costs


5,244


4,925Production expense

$
58,170


62,541Production expense per Mcfe:Lease operating expenses

$
.83


.86Production and property taxes


.24


.46Transportation and processing costs


.11


.11Production expense per Mcfe

$
1.18


1.44


Lease
operating expenses in the first quarter 2009 were $41 million, or $.83 per Mcfe, compared to $38 million, or $.86 per Mcfe, in the first quarter 2008. Lease operating
expense decreased on a per-unit basis in the comparable three month periods due primarily to a decrease in workover expenses. Production and property taxes, which primarily consist of
severance taxes paid on the value of the oil and gas produced, generally fluctuate proportionately to our oil and gas revenues. As a percentage of oil and natural gas revenue, production and property
taxes were 6.0% and 5.3% for the three months ended March 31, 2009 and 2008, respectively. In addition, normal fluctuations will occur between periods based on the approval of incentive tax
credits in Texas, changes in tax rates, and changes in the assessed values of property and equipment for purposes of ad valorem taxes. Transportation and processing costs were $5 million, or
$.11 per Mcfe, in both the first quarter 2009 and 2008.

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General and Administrative Expense

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

Three Months
Ended
March 31,2009

2008(In Thousands,
Except
Per Mcfe Data)Stock-based compensation costs

$
6,373


6,050Other general and administrative costs


20,157


25,349General and administrative costs capitalized


(10,445
)

(12,111
)General and administrative expense

$
16,085


19,288General and administrative expense per Mcfe

$
.33


.44


General
and administrative expense in the first quarter 2009 was $16 million compared to $19 million in the first quarter 2008. The $3 million decrease in general
and administrative expense in the comparable three month periods was primarily due to decreased employee compensation costs and contract labor. On a per-unit basis, general and
administrative expense decreased 25% to $.33 per Mcfe in the first quarter 2009 from $.44 per Mcfe in the first quarter 2008. The percentage of general and administrative costs capitalized was 39% for
each period presented.

Depreciation and Depletion

Depreciation, depletion, and amortization expense in the first quarter 2009 was $105 million, or $2.11 per Mcfe, compared to
$116 million, or $2.66 per Mcfe, in the first
quarter 2008. The per-unit decrease for the comparable three month periods was primarily due to a $2.4 billion non-cash ceiling test write-down recorded in
the fourth quarter 2008. Depreciation, depletion, and amortization expense is expected to decrease further beginning in the second quarter of 2009 due to the additional ceiling test
write-down recorded as of March 31, 2009 (discussed below).

Ceiling Test Write-Down of Oil and Gas Properties

In the first quarter 2009, Forest recorded a ceiling test write-down for both its United States and Canadian cost centers
pursuant to the ceiling test limitation prescribed by the Securities and Exchange Commission ("SEC") for companies using the full cost method of accounting. The write-down totaled
$1.6 billion and was primarily a result of a significant decline in natural gas prices in the first quarter of 2009. The March 31, 2009 NYMEX spot price for natural gas was $3.63 per
MMBtu compared to $5.71 at December 31, 2008. Additional write-downs of the full cost pools in the United States and Canada may be required in subsequent periods if natural gas or oil prices
decline from March 31, 2009 levels, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition
activities in the respective full cost pools exceed the discounted future net cash flows from the additional reserves, if any, attributable to each of the cost pools. See Part II,
Item 1A,"Risk Factors""Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and
other impairments of our asset carrying values."

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Interest Expense

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

Three Months
Ended
March 31,2009

2008(In Thousands)Interest costs

$
39,948


33,067Interest costs capitalized


(3,403
)

(5,210
)Interest expense

$
36,545


27,857


Interest
expense in the first quarter 2009 totaled $37 million compared to $28 million in the first quarter 2008. The $9 million increase in interest expense between
the comparable three month periods was primarily due to increased average debt balances in the first quarter of 2009 offset by a decrease in average interest rates in the first quarter of 2009. Our
average debt balance increased in the first quarter of 2009 as compared to the same period of the prior year primarily due to the acquisition of oil and natural gas properties from Cordillera
Texas, L.P. in September 2008 (see Note 5 to the Condensed Consolidated Financial Statements). Interest costs capitalized decreased by $2 million in the first quarter 2009 as
compared to the first quarter 2008 due primarily to lower average interest rates in 2009 and the amortization of unproved properties to proved properties throughout 2008 and 2009. 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.

Realized and Unrealized Gains and Losses

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

Three Months Ended
March 31,2009

2008(In Thousands)Realized (gains) losses on derivatives, net:Oil

$
(10,449
)

16,702Gas


(60,816
)

(13,323
)Interest


(524
)

284Subtotal realized


(71,789
)

3,663Unrealized losses (gains) on derivatives, net:Oil


5,567


14,759Gas


(71,351
)

122,671Interest


(1,755
)

4,783Subtotal unrealized


(67,539
)

142,213Realized and unrealized (gains) losses on derivatives, net

$
(139,328
)

145,876


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Foreign Currency Exchange

Unrealized foreign currency exchange gains and losses relate to the outstanding intercompany indebtedness, which is denominated in U.S.
dollars, between Forest Oil Corporation and our Canadian subsidiary. The strengthening of the U.S. dollar in both three month periods ended March 31, 2009 and 2008 resulted in unrealized
foreign exchange losses of $4 million and $3 million, respectively. Realized foreign currency exchange gains and losses relate to repayments of the indebtedness to Forest Oil Corporation
by our Canadian subsidiary. There were no such repayments during either of the three month periods ended March 31, 2009 and 2008.

Other Investments

Unrealized losses on other investments totaled $2 million and $7 million for the three months ended March 31, 2009
and 2008, respectively. The unrealized losses on other investments relate to fair value adjustments to the shares of Pacific Energy Resources, Ltd. ("PERL") common stock and the
zero coupon senior subordinated note from PERL due 2014, which were
received as a portion of the total consideration for the sale of our Alaska assets in August 2007. In March 2009, PERL filed voluntary petitions for reorganization under Chapter 11 of the U.S.
Bankruptcy Code. The bankruptcy proceedings are still at a very early stage; however, PERL has indicated that the value of its assets is less than the amount of PERL's senior
unsubordinated debt. Based on these facts and circumstances, we estimated the fair value of the PERL common stock and note to be zero as of March 31, 2009. See Note 7 to the Condensed
Consolidated Financial Statements for more information on these investments.

Current and Deferred Income Tax

Our effective income tax rate was approximately 20% for the three months ended March 31, 2009 and 33% for the three months ended
March 31, 2008. The significant decrease in our effective tax rate to 20% in 2009 is primarily due to the valuation allowance placed on a portion of our deferred tax assets in the United States as of
March 31, 2009. See Note 9 to the Condensed Consolidated Financial Statements and"Critical Accounting Policies, Estimates, Judgments, and
Assumptions""Valuation of Deferred Tax Assets"for more information on our income taxes and valuation allowance.

LIQUIDITY AND CAPITAL RESOURCES

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

Changes
in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. For the quarter ended March 31, 2009, natural gas accounted
for approximately 76% of our total oil and gas production and, as a result, our operations and cash flow are more sensitive to fluctuations in the price for natural gas. We employ a commodity hedging
strategy in order to try to minimize the adverse effects of wide fluctuations in commodity prices on our cash flow. As of April 30, 2009, we had hedged, via commodity swaps and collar
instruments, approximately 94 Bcfe of our 2009 production and 58 Bcfe of our 2010 production. This level of hedging will provide a measure of certainty of the cash flow that we will receive for a
portion of our production in 2009 and 2010. In the future, we may determine to increase or decrease our hedging positions. As of April 30, 2009, all of our derivatives counterparties were
commercial banks that are parties to our credit

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facilities,
or their affiliates. For further information concerning our derivative contracts, see Item 3"Quantitative and Qualitative Disclosures About Market
RiskCommodity Price Risk" below.

The
other primary sources of liquidity include our U.S. credit facility and our Canadian credit facility, which had a borrowing base of $1.62 billion as of March 31, 2009.
These facilities are used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facilities are secured by a portion of our assets and mature in
June 2012. We had approximately $700 million available under these facilities as of March 31, 2009. See the heading"Bank Credit
Facilities"below for further details.

The
public and private capital markets have served as our primary source of financing to fund large acquisitions and other exceptional transactions. In the past, we have issued debt and
equity in both the public and private capital markets. For example, on February 17, 2009, we issued $600 million principal amount of 81/2% senior notes due 2014 in a
private offering. Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the domestic and global financial markets, the credit
ratings assigned to our debt by independent credit rating agencies, our operational and financial performance, the value and performance of our equity and debt securities, prevailing commodity prices,
and other macroeconomic factors outside of our control. Notwithstanding that we recently completed a $600 million issuance of senior notes, the continuing economic crisis and distressed
financial markets have impacted our business and limited our ability to access the capital markets on economical terms as funding from these markets has diminished significantly. We cannot be certain
that funding will be available to us in the debt and equity markets in the future, if needed, nor can we be certain that such funding will be available on acceptable terms.

We
also have engaged in asset dispositions as a means of generating additional cash to fund expenditures and enhance our financial flexibility. For example, during 2008, we sold certain
non-strategic assets for total proceeds of approximately $310 million. However, due to significant declines in oil and natural gas prices and the turmoil in the financial and credit
markets over the last year, the level of activity in the market for oil and gas properties has greatly diminished, as has the pool of available buyers. We intend to pursue asset dispositions in the
future, including our previously announced intention to sell certain non-core properties. Due to the current economic conditions, however, this program has been delayed. We hope to
complete these divestitures
by year end 2010, assuming market conditions and property valuations improve, but cannot predict whether we will be able to complete any asset divestitures.

We
believe that our cash flow provided by operating activities and funds available under our credit facilities will be sufficient to fund our operating and capital expenditures budget,
and our short-term contractual obligations during 2009. However, if our revenue and cash flow decrease in the future as a result of further deterioration in domestic and global economic
conditions and a continuation of declining commodity prices, we may have to reduce further our spending levels. We believe that this financial flexibility to adjust our spending levels will provide us
with sufficient liquidity to meet our financial obligations should economic conditions not improve during 2009. See Part I, Item 1A,"Risk Factors," of our 2008 Annual Report
on Form 10-K and Part II, Item 1A of this report.

Bank Credit Facilities

On March 16, 2009, we entered into the Second Amendment (the "Second Amendment") to our second amended and restated combined
credit agreements dated as of June 6, 2007 that amended certain definitions and covenants of the credit agreements, including the total debt outstanding-to-EBITDA ratio.
The effective date of the Second Amendment is March 16, 2009. The second amended and restated combined credit agreements consist of a $1.65 billion U.S. credit facility (the "U.S.
Facility") with a syndicate of banks led by JPMorgan Chase Bank, N.A., and a $150 million Canadian credit facility (the "Canadian Facility," and together with the U.S. Facility, the "Credit

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Facilities")
with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Credit Facilities will mature in June 2012.

Forest's
availability under the Credit Facilities is governed by a borrowing base (the "Global Borrowing Base"). 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 to the semi-annual
redeterminations, Forest and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the Global Borrowing Base redetermined. Because the process for
determining the Global Borrowing Base involves evaluating the estimated value of our oil and gas properties using pricing models determined by the lenders at that time, the recent decline in oil and
gas commodity prices, or a further decline in those prices, could result in a determination to decrease the Global Borrowing Base in the future.

The
Global Borrowing Base is also subject to change in the event (i) we issue senior notes, in which case the Global Borrowing Base will immediately be reduced by an amount equal
to $0.30 for every $1.00 principal amount of any newly issued senior notes, excluding any senior notes that we may issue to refinance senior notes that were outstanding on May 9, 2008, or
(ii) if we sell oil and natural gas properties included in the Global Borrowing Base having a fair market value in excess of 10% of the Global Borrowing Base then in effect. The Global
Borrowing Base is subject to other automatic adjustments under the facilities. As a result of issuing $600 million of 81/2% senior notes due 2014 in February 2009, our borrowing
base was lowered from $1.8 billion to $1.62 billion effective February 17, 2009. As a result of the adjustment to the Global Borrowing Base, we reallocated amounts under the U.S.
Facility and Canadian Facility and currently have allocated $1.47 billion to the U.S. Facility and $150 million to the Canadian Facility. A lowering of the Global Borrowing Base could
require us to repay indebtedness in excess of the Global Borrowing Base in order to cover the deficiency. The automatic lowering of the Global Borrowing Base on February 17, 2009 did not result
in any deficiency, and therefore we did not have to repay any amounts. On March 16, 2009, we announced that our bank group reaffirmed our $1.62 billion Global Borrowing Base and
$1.8 billion nominal amount related to the Credit Facilities. The next redetermination of the borrowing base is scheduled to be in the fourth quarter of 2009.

Borrowings
under the U.S. Facility bear interest at one of two rates as may be elected by Forest. Loans will bear interest at a rate that is based on interest rates applicable to dollar
deposits in the London interbank market ("LIBO Rate"), or a rate based on the greater of (i) the prime rate announced by the global administrative agent; (ii) the federal funds rate plus
1/2 of 1%; and (iii) the Adjusted LIBO Rate for a one month Interest Period on such day plus 1%. Loans under the Canadian Facility will bear interest at a rate that may be based
on the base rate announced by the Canadian administrative agent, the LIBO Rate, a rate based on the greater of the rate for U.S. dollar denominated loans made by the Canadian administrative agent and
the federal funds rate plus 1/2 of 1%, or a banker's acceptance rate.

The
Credit Facilities include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens,
asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also include financial covenants. For example, the Credit Facilities provide that Forest will not permit its
total debt outstanding-to-EBITDA ratio to be greater than (i) 4.50 to 1.00 for four consecutive fiscal quarters ending in 2009 and 2010; (ii) 4.00 to 1.00 for
four consecutive fiscal quarters ending in 2011; and (iii) 3.50 to 1.00 at any time thereafter. If we were to fail to perform our obligations under these covenants or other covenants and
obligations, it could cause an event of default and the Credit Facilities could be terminated and amounts outstanding could be declared immediately due and payable

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by
the lenders, subject to notice and cure periods in certain cases. Such events of default include non-payment, breach of warranty, non-performance of financial covenants,
default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, a failure of the liens securing the Credit Facilities, and an event of default under the
Canadian Facility. In addition, bankruptcy and insolvency events with respect to Forest or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit
Facilities. An acceleration of our indebtedness under the Credit Facilities could in turn result in an event of default
under the indentures for our senior notes, which in turn could result in the acceleration of the senior notes. For example, the indentures for our 8% senior notes due 2011 and our 73/4%
senior notes due 2014 include as events of default, among others, a default on indebtedness that results in the acceleration of indebtedness in an amount greater than $10 million; each of the
indentures for our 81/2% senior notes due 2014 and our 71/4% senior notes due 2019 include a similar event of default if the amount involved is greater than
$25 million.

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

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

From
time to time, we engage in other transactions with a number of the lenders under the Credit Facilities. Such lenders or their affiliates may serve as underwriter or initial
purchaser of our debt and equity securities, act as agent or directly purchase our production, or serve as counterparties to our commodity and interest rate derivative agreements. As of
April 30, 2009, our primary derivative counterparties included the following lenders and their affiliates: BMO, BNP Paribas, Barclays, Credit Suisse, Deutsche Bank, Fortis, Bank of Nova Scotia,
Toronto Dominion, Bank of America, U.S. Bank National Association, and Wells Fargo. As of April 30, 2009, our derivative transactions with BMO, Credit Suisse, Fortis, Bank of Nova Scotia, BNP
Paribas, and Toronto Dominion accounted for approximately 85 Bcfe, or 91% of our 2009 hedged production, and 42 Bcfe, or 73% of our 2010 hedged production. Our obligations under our existing
derivative agreements with our lenders are secured by the security documents executed by the parties under our Credit Facilities. See Item 3"Quantitative and Qualitative
Disclosures about Market
RiskCommodity Price Risk," below for additional details concerning our derivative arrangements.

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At
March 31, 2009, there were outstanding borrowings of $800.0 million under the U.S. Facility at a weighted average interest rate of 1.8%, and there were outstanding
borrowings of $112.6 million under the Canadian Facility at a weighted average interest rate of 2.1%. We also had used the Credit Facilities for $2.7 million in letters of credit,
leaving an unused borrowing amount under the Credit Facilities of $704.7 million at March 31, 2009. At April 30, 2009, there were outstanding borrowings of $800.0 million
under the U.S. Facility at a weighted average interest rate of 1.7%, and there were outstanding borrowings of $135.8 million under the Canadian Facility at a weighted average interest rate of
2.1%. We also had used the Credit Facilities for $2.7 million in letters of credit, leaving an unused borrowing amount under the Credit Facilities of $681.5 million at April 30,
2009.

Credit Ratings

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

Historical Cash Flow

Net cash provided by operating activities, net cash used by investing activities, and net cash provided by financing activities for the
three months ended March 31, 2009 and 2008 were as follows:

Three Months Ended
March 31,2009

2008(In Thousands)Net cash provided by operating activities

$
148,366


207,072Net cash used by investing activities


(316,877
)

(263,607
)Net cash provided by financing activities


167,182


48,859


Cash
flows provided by operating activities are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes
in working capital. The decrease in net cash provided by operating activities in the three months ended March 31, 2009 compared to the same period of 2008 was primarily due to lower net
earnings before non-cash charges partially offset by a decreased investment in net operating assets in 2009 as compared to 2008.

Cash
flows used by investing activities are primarily comprised of the acquisition, exploration and development of oil and gas properties net of dispositions of oil and gas properties.
The increase in net cash used by investing activities in the three months ended March 31, 2009 compared to the same period of 2008 was primarily due to more payments for exploration and
development activities in 2009, which includes the payment of 2008 capital expenditures accrued as of December 31, 2008 but not paid until the first quarter of 2009. See
"Capital Expenditures" below.

Net
cash provided by financing activities in the three months ended March 31, 2009 included the issuance of 81/2% senior notes for net proceeds of
$560 million, offset by net repayments of bank

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borrowings
of $369 million. Net cash provided by financing activities in the three months ended March 31, 2008 included net bank proceeds of $43 million.

Capital Expenditures

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

Three Months Ended
March 31,2009

2008(In Thousands)Property acquisition costs:Proved properties

$



16,782Unproved properties





400


17,182Exploration and development costs:Direct costs


238,953


233,316Overhead capitalized


10,445


12,111Interest capitalized


3,403


5,210252,801


250,637Total capital expenditures(1)

$
252,801


267,819






Due to significant changes in the overall economy as well as the price for oil and natural gas, we have chosen to significantly reduce our capital
expenditures and drilling activity in 2009 compared with 2008. We intend to keep our full-year 2009 exploration and development capital spending within our 2009 cash flows from operations;
however, due to continuing declines in oil and natural gas prices, this may not be achievable. We have established a capital budget of approximately $500 million to $600 million for the
year ending December 31, 2009. Some of the factors impacting the level of capital expenditures in 2009 include crude oil and natural gas prices, the volatility in these prices, the cost and
availability of oil field services, general economic and market conditions, and weather disruptions.

CRITICAL ACCOUNTING POLICIES, ESTIMATES, JUDGMENTS, AND ASSUMPTIONS

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

Full Cost Method of Accounting

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

Under
the full cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration, and development of
properties (including

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costs
of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs
of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded. Capitalized costs applicable to each full cost
center are depleted using the units of production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in
estimates of reserves or future development costs are accounted for prospectively in the depletion calculations. Assuming consistent production year over year, our depletion expense will be
significantly higher or lower if we significantly decrease or increase our estimates of remaining proved reserves.

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

Companies
that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling
test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed each quarter on a country-by-country
basis. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and
natural gas reserves, as adjusted for asset retirement obligations and the effect of cash flow hedges. This ceiling is compared to the net book value of the oil and gas properties reduced by any
related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is
required. Forest recorded a $1.6 billion ceiling test write-down in the first quarter of 2009. The March 31, 2009 NYMEX spot prices for natural gas and oil were $3.63 per
MMBtu and $49.66 per barrel, respectively. Additional write-downs of the full cost pools in the United States and Canada may be required in 2009 if oil and natural gas prices decline further, unproved
property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in the respective full cost pools exceed the
discounted future net cash flows from the additional reserves, if any, attributable to each of the cost pools.

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

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

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

Valuation of Deferred Tax Assets

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

In
assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets
will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax
assets, as well as future taxable income is sufficient to utilize net operating and other credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the
evaluation of all available evidence, both negative and positive. Negative evidence considered by management included a recent history of book losses driven in large part from ceiling test write-downs
and, given the decline in oil and gas prices and
accelerated depreciation and amortization used for tax purposes, projected taxable losses over the next several years. Positive evidence considered by management included forecasted book income over a
reasonable period of time and the fact that our net operating loss carryforwards do not expire until after 2017. Based upon the evaluation of what management determined to be relevant evidence, we
have recorded a valuation allowance of approximately $216 million against our U.S. deferred tax assets as of March 31, 2009, leaving a net deferred tax asset attributable to the U.S. of
approximately $100 million. See Note 9 to the Condensed Consolidated Financial Statements.

The
primary evidence utilized to determine that it is more likely than not that a portion of the deferred tax asset will be realized was management's expectation of future book income
over the next several years, despite the negative evidence of recent book losses caused by ceiling test write-downs in both the fourth quarter of 2008 and the first quarter of 2009. These ceiling test
write-downs, which are not considered a fair value impairment test, have dramatically reduced our prospective depletion rate, making future book income more likely than would be the case had these
ceiling test write-downs not occurred. Despite a lower expected depletion rate, our projection of future book income is most contingent on projected oil and gas prices, which are based on quoted NYMEX
oil and gas futures. Accordingly, the amount of the deferred tax asset considered realizable will likely change each quarter as estimates of our future book income change due to changes in expected
future oil and gas prices, and these changes could be material. For example, had the forecasted price used for oil and natural gas been 10% lower during the projected periods, our valuation allowance
would have likely increased by approximately $50 million.

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FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q including "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in Item 2 of Part I of this report, contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements, other than statements of historical 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. 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 2008
Annual Report on Form 10-K and the risks described in Item 1A of Part II in this report.

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



We
believe the expectations and forecasts reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that
these forward-looking statements can be affected by inaccurate assumptions and are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond
our control, incident to the exploration for and development, production, and sale of oil and gas. When considering

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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 our 2008 Annual Report on
Form 10-K and the risks described in Item 1A of Part II in this report. These risks include, but are not limited to, the following:



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

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

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Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices, 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.

Hedging Program

In order to reduce the impact of fluctuations in commodity prices, or to protect the economics of property acquisitions, we make use of
an oil and gas hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other financial instruments with counterparties who, in general, are participants in our credit
facilities. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of
hydrocarbons.

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 March 31, 2009, we had entered into the following swaps:

SwapsNatural Gas (NYMEX HH)

Oil (NYMEX WTI)Bbtu
per Day(1)

Weighted Average
Hedged Price
per MMBtu

Fair Value
(In Thousands)

Barrels
per Day

Weighted Average
Hedged Price
per Bbl

Fair Value
(In Thousands)April 2009 - October 2009


210

$
7.33

$
142,697


4,500

$
69.01

$
14,290November 2009 - December 2009


160


8.24


27,732


4,500


69.01


2,851Calendar 2010


150


6.36


22,327


1,500


72.95


5,336


---

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

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the
index price only if the index price is above the ceiling price. As of March 31, 2009, we had entered into the following collars:

Costless CollarsNatural Gas (NYMEX HH)Bbtu
per Day

Weighted Average
Hedged Floor and
Ceiling Price
per MMBtu

Fair Value
(In Thousands)April 2009 - December 2009


40

$
7.31/9.76

$
33,611


Basis Swaps

Forest also uses basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX Henry Hub
price and the index price at which the natural gas production is sold. As of March 31, 2009, we had entered into the following basis swaps:

Index

Bbtu
Per Day

Weighted
Average
Hedged Price
Differential
per MMBtu

Fair Value
(In Thousands)April 2009 - December 2009

AECO


25

$
(.65
)
$
602April 2009 - December 2009

Centerpoint


30


(.95
)

(1,108
)April 2009 - December 2009

Houston Ship Channel


50


(.33
)

(959
)April 2009 - December 2009

Mid Continent


60


(1.04
)

(3,687
)April 2009 - December 2009

NGPL TXOK


40


(.53
)

(271
)Calendar 2010

Centerpoint


30


(.95
)

(2,337
)Calendar 2010

Mid Continent


60


(1.04
)

(5,190
)


Subsequent
to March 31, 2009, through April 30, 2009, we entered into additional basis swaps covering 40 Bbtu per day for Calendar 2010 at a weighted average hedged price
differential of $(.44) for the NGPL TXOK index.

The
fair value of all our commodity derivative instruments based on various inputs, including published forward prices, at March 31, 2009 was a net asset of approximately
$235.9 million.

Interest Rate Derivatives

Forest periodically enters into interest rate derivative agreements in an attempt to normalize the mix of fixed and floating interest
rates within its debt portfolio. In June 2008, we terminated all of our interest rate swaps outstanding at the time and did not enter into any new interest rate derivatives until 2009. In February
2009, we entered into the following fixed to floating interest rate swap:

Swap Term

Notional
Amount
(In Thousands)

Floating Rate

Fixed
Rate

Fair Value
(In Thousands)February 2009 - February 2014

$
100,000

1 month LIBOR + 6.00%


8.50
%
$
1,280


In addition to the interest rate swap, during the three months ended March 31, 2009, we entered into certain interest rate swaptions, which
enable the counterparties to exercise options to enter into interest rate swaps with us. We received premiums on these swaptions. The interest rate swaps underlying the swaptions also exchange the
8.5% fixed interest rate on a portion of the 81/2% senior notes that we issued in February 2009 for a variable rate over the term of the 81/2% senior notes. We entered
into these interest rate swaptions as our target interest rates are currently not attainable in the interest rate swap market. The table below sets forth our outstanding interest rate swaptions as of

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March 31,
2009. Subsequent to March 31, 2009, through April 30, 2009, the counterparties have not exercised their options.

Option Term

Swap Term

Premiums
Received
(In Thousands)

Notional
Amount
(In Thousands)

Weighted Average
Floating Rate

Weighted
Average
Fixed
Rate

Fair Value
(In Thousands)March 2009 - June 2009

June 2009 -
February 2014

$
1,322

$
200,000

1 month LIBOR + 5.85%


8.50
%
$
(546
)


Subsequent to March 31, 2009, through April 30, 2009, we entered into additional interest rate swaptions with the following terms:

Option Term

Swap Term

Premiums
Received
(In Thousands)

Notional
Amount
(In Thousands)

Weighted Average
Floating Rate

Weighted
Average
Fixed
RateApril 2009 - July 2009

July 2009 - February 2014

$
1,065

$
225,000

1 month LIBOR + 5.88%


8.50
%


Fair Value Reconciliation

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

Fair Value of Derivative ContractsCommodity

Interest Rate

Total(In Thousands)As of December 31, 2008

$
170,111





170,111Premiums received





(1,322
)

(1,322
)Net increase in fair value


137,048


2,580


139,628Net contract gains recognized


(71,265
)

(524
)

(71,789
)As of March 31, 2009

$
235,894


734


236,628


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.

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Interest Rate Risk

The following table presents principal amounts and related interest rates by year of maturity for Forest's debt obligations at
March 31, 2009.

2011

2012

2013

2014

2019

Total(Dollar Amounts in Thousands)Bank credit facilities:Variable rate

$



912,578











912,578Average interest rate(1)





1.84
%










1.84
%Long-term debt:Fixed rate

$
285,000





1,112


750,000


1,000,000


2,036,112Weighted average coupon interest rate


8.00
%




7.00
%

8.35
%

7.25
%

7.76
%Weighted average effective interest rate(2)


7.71
%




7.00
%

8.11
%

7.25
%

7.63
%


---

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 March 31, 2009 (the "Evaluation Date"). Based on this evaluation, they believe that as of the Evaluation Date our
disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the 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
March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART IIOTHER INFORMATION

Item 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, 2008 ("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.

Oil and natural gas prices are volatile. Recent declines in commodity prices have adversely affected, and in the future will adversely affect, our financial condition and
results of operations, cash flows, access to the capital markets, and ability to grow.

Our financial condition, operating results, and future rate of growth depend upon the prices that we receive for our oil and natural
gas. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our bank credit facilities and through the capital markets. The amount available for
borrowing under our bank credit facilities is subject to a global borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to periodic
redeterminations based on pricing models determined by the lenders at such time. The recent decline in oil and natural gas prices has adversely impacted the value of our estimated proved reserves and,
in turn, the market values used by our lenders to determine our global borrowing base. If commodity prices remain at these current low levels for the remainder of 2009, or decrease further, it will
have similar adverse effects on our reserves and global borrowing base. Further, because we have elected to use the full-cost accounting method, we must perform each quarter a "ceiling
test" that is impacted by declining commodity prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges
against current earnings. For example, as a result of the dramatic declines in oil and natural gas prices in the second half of 2008, we recorded a non-cash ceiling test
write-down of $2.4 billion for the three months and year ended December 31, 2008. The write-down resulted in a charge to net earnings and the recording of a net
loss in 2008. Further, we recorded an additional non-cash ceiling test write-down of $1.6 billion for the three months ended March 31, 2009. See "Lower oil and gas prices and other factors have resulted, and in
the future may result, in ceiling test write-downs and other impairments of our asset carrying
values."

In
addition, significant or extended commodity price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production
could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our
ability to replace our production and our future rate of growth.

The
markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. Oil spot prices reached historical highs in July 2008, peaking at
more than $145 per barrel, and natural gas spot prices reached near historical highs in July 2008, peaking at more than $13 per MMBtu. These prices have declined significantly since that time and may
continue to fluctuate widely in the future. The prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:



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These
factors make it very difficult to predict future commodity price movements with any certainty. We sell the majority of our oil and natural gas production at current prices rather
than through fixed-price contracts. However, we do enter into derivative instruments to reduce our exposure to fluctuations in oil and natural gas prices. See "Our
use of hedging transactions could result in financial losses or reduce our income." Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation
to each other. Approximately 75% of our estimated proved reserves at December 31, 2008 were natural gas, and, as a result, our financial results will be more sensitive to fluctuations in
natural gas prices.

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

As of April 30, 2009, the principal amount of our outstanding consolidated debt was approximately $3.0 billion, which
amount included approximately $936 million outstanding under our combined U.S. and Canadian credit facilities. Our level of indebtedness has several important effects on our business and
operations; among other things, it may:



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

Our
credit and debt agreements contain various restrictive covenants. A failure on our part to comply with the financial and other restrictive covenants contained in our bank credit
facilities and the indentures pertaining to our outstanding senior notes could result in a default under these agreements.

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Any
default under our bank credit facilities or indentures could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing
in the future. In addition, the global borrowing base included in our bank credit facilities is subject to periodic redetermination by our lenders. A lowering of our global borrowing base could
require us to repay indebtedness in excess of the borrowing base.

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

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

To reduce our exposure to fluctuations in oil and natural gas prices, we have entered into and expect in the future to enter into
derivative instruments (or hedging agreements) for a portion of our oil and natural gas production. Our commodity hedging agreements are limited in duration, usually for periods of two years or less;
however, in conjunction with acquisitions, we sometimes enter into or acquire hedges for longer periods. As of April 30, 2009, we had hedged, via commodity swaps and collar instruments,
approximately 94 Bcfe of our 2009 production and 58 Bcfe of our 2010 production. Our hedging transactions expose us to certain risks and financial losses, including, among
others:



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

Currently,
all of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our bank credit facilities. As of April 30, 2009,
our primary derivative counterparties included the following lenders and their affiliates: BMO Capital Markets Financing, Inc. ("BMO"), BNP Paribas, Barclays Bank PLC ("Barclays"),
Credit Suisse, Deutsche Bank AG New York Branch ("Deutsche Bank"), Fortis Capital Corp. ("Fortis"), The Bank of Nova Scotia, Toronto Dominion (Texas) LLC and The Toronto-Dominion Bank
(collectively, "Toronto Dominion"), Bank of America, U.S. Bank National Association, and Wells Fargo Bank, N.A. ("Wells Fargo"). As of April 30, 2009, our derivative transactions with BMO,
Credit Suisse, Fortis, The Bank of Nova Scotia, BNP Paribas, and Toronto Dominion accounted for approximately 85 Bcfe, or 91% of our 2009 hedged production, and 42 Bcfe, or 73% of our 2010 hedged
production. Our obligations under our existing

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derivative
agreements with our lenders are secured by the security documents executed by the parties under our bank credit facilities.

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

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

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

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

The
risk that we will be required to write-down the carrying value of our oil and gas properties, our unproved properties, or goodwill increases when oil and gas prices are
low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future
development costs increase. For example, oil and natural gas prices declined significantly during the second half of 2008. At December 31, 2008, the spot prices for oil and natural gas were
$44.60 per barrel and $5.71 per MMBtu, respectively. Based on these prices, we recorded a non-cash ceiling test write-down of $2.4 billion for the three months and year
ended December 31, 2008. At March 31, 2009, the spot prices for oil and natural gas were $49.66 per barrel and $3.63 per MMBtu, respectively. Based on these prices, we recorded an
additional non-cash ceiling test write-down of $1.6 billion for the three months ended March 31, 2009. The write-downs are reflected as a charge to net earnings.
Additional write-downs of the full cost pools in the United States and Canada may be required in 2009 if oil and natural gas prices decline further, unproved property values decrease, estimated proved
reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in the respective full cost pools exceed the discounted future net cash flows from the
additional reserves, if any, attributable to each of the cost pools.

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

Unregistered Sales of Securities

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

Issuer Purchases of Equity Securities

The table below sets forth information regarding repurchases of our common stock during the first quarter 2009. The shares repurchased
represent shares of our common stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of shares of restricted stock and phantom stock units
that are settled in shares. Forest does not consider this a share buyback program.

Period

Total # of Shares
Purchased

Average Price
Per Share

Total # of Shares
Purchased as Part of
Publicly Announced
Plans or Programs

Maximum # (or
Approximate Dollar
Value) of Shares that
May yet be Purchased
Under the Plans or
ProgramsJanuary 2009


1,406

$
15.93





February 2009


4,302


18.97





March 2009


839


13.38





First Quarter Total


6,547

$
17.60








Item 6.    EXHIBITS



4.1

Second Amendment dated March 16, 2009, to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders that is a
party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and JPMorgan Chase Bank, N.A., Toronto Branch, as Canadian Administrative Agent, incorporated by reference to Exhibit 4.1 to Form 8-K dated March 16, 2009 (File
No. 001-13515).10.1
*
Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended.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.






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SIGNATURES

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

FOREST OIL CORPORATION(Registrant)May 7, 2009By:

/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)


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Exhibit Index

Exhibit
Number

Description10.1
*
Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended.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.


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