Edgar Filing: FOREST OIL CORP

FST-03.31.2013-10Q



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

__________________________________________________

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2013



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

For the transition period from to

Commission File Number 1-13515

FOREST OIL CORPORATION

(Exact name of registrant as specified in its charter)



New York	25-0484900
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)



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

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

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

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

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



Large accelerated filer x	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company ¨

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

As of May 2, 2013 there were 119,292,850 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, 2013



Part I—FINANCIAL INFORMATION	1
Item 1—Financial Statements	1
Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	1
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2013 and 2012	3
Condensed Consolidated Statement of Equity for the Three Months Ended March 31, 2013	4
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012	5
Notes to Condensed Consolidated Financial Statements	6
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3—Quantitative and Qualitative Disclosures About Market Risk	35
Item 4—Controls and Procedures	37
Part II—OTHER INFORMATION	38
Item 1—Legal Proceedings	38
Item 1A—Risk Factors	38
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 6—Exhibits	39
Signatures	40

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands, Except Share Amounts)



	March 31, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	1,225		$	1,056
Accounts receivable	81,879			67,516
Derivative instruments	10,094			40,190
Other current assets	16,864			16,318
Total current assets	110,062			125,080
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $8,284,724 and $8,237,186	1,229,752			1,459,312
Unproved	233,364			277,798
Net oil and natural gas properties	1,463,116			1,737,110
Other property and equipment, net of accumulated depreciation and amortization of $47,778 and $46,908	15,383			17,128
Net property and equipment	1,478,499			1,754,238
Deferred income taxes	4,150			14,681
Goodwill	239,420			239,420
Derivative instruments	3,780			8,335
Other assets	59,073			60,108
	$	1,894,984		$	2,201,862
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	181,179		$	164,786
Accrued interest	23,803			23,407
Derivative instruments	15,772			9,347
Deferred income taxes	4,150			14,681
Current portion of long-term debt	12			12
Other current liabilities	12,927			14,092
Total current liabilities	237,843			226,325
Long-term debt	1,640,351			1,862,088
Asset retirement obligations	23,699			56,155
Derivative instruments	4,440			7,204
Other liabilities	93,402			92,914
Total liabilities	1,999,735			2,244,686
Shareholders’ equity:
Preferred stock, none issued and outstanding	—			—
Common stock, 119,330,398 and 118,245,320 shares issued and outstanding	11,933			11,825
Capital surplus	2,547,430			2,541,859
Accumulated deficit	(2,643,942		)	(2,575,994		)
Accumulated other comprehensive loss	(20,172		)	(20,514		)
Total shareholders’ equity (deficit)	(104,751		)	(42,824		)
	$	1,894,984		$	2,201,862

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands, Except Per Share Amounts)



	Three Months Ended
	March 31,
	2013			2012
Revenues:
Oil, natural gas, and natural gas liquids sales	$	118,042		$	158,901
Interest and other	132			32
Total revenues	118,174			158,933
Costs, expenses, and other:
Lease operating expenses	21,204			27,607
Production and property taxes	2,216			11,153
Transportation and processing costs	3,280			3,972
General and administrative	20,014			15,384
Depreciation, depletion, and amortization	48,543			66,970
Ceiling test write-down of natural gas properties	—			34,817
Interest expense	36,128			33,392
Realized and unrealized losses (gains) on derivative instruments, net	25,580			(29,524		)
Other, net	28,820			26,920
Total costs, expenses, and other	185,785			190,691
Loss before income taxes	(67,611		)	(31,758		)
Income tax	337			915
Net loss	$	(67,948	)	$	(32,673	)

Basic loss per common share	$	(.59	)	$	(.29	)
Diluted loss per common share	$	(.59	)	$	(.29	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In Thousands)



	Three Months Ended
	March 31,
	2013			2012
Net loss	$	(67,948	)	$	(32,673	)
Other comprehensive income:
Defined benefit postretirement plans - amortization of actuarial losses, net of tax	342			187
Total other comprehensive income	342			187

Total comprehensive loss	$	(67,606	)	$	(32,486	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

(In Thousands)



	Common Stock					Capital Surplus			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity (Deficit)
	Shares		Amount			Capital Surplus			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity (Deficit)
Balances at December 31, 2012	118,245		$	11,825		$	2,541,859		$	(2,575,994	)	$	(20,514	)	$	(42,824	)
Employee stock purchase plan	54		5			222			—			—			227
Restricted stock issued, net of forfeitures	1,105		110			(110		)	—			—			—
Amortization of stock-based compensation	—		—			5,944			—			—			5,944
Other, net	(74	)	(7		)	(485		)	—			—			(492		)
Net loss	—		—			—			(67,948		)	—			(67,948		)
Other comprehensive income	—		—			—			—			342			342
Balances at March 31, 2013	119,330		$	11,933		$	2,547,430		$	(2,643,942	)	$	(20,172	)	$	(104,751	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)



	Three Months Ended
	March 31,
	2013			2012
Operating activities:
Net loss	$	(67,948	)	$	(32,673	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	48,543			66,970
Deferred income tax	—			1,133
Unrealized losses (gains) on derivative instruments, net	38,311			(5,312		)
Ceiling test write-down of natural gas properties	—			34,817
Stock-based compensation expense	3,647			3,017
Accretion of asset retirement obligations	1,244			1,598
Loss on debt extinguishment	25,223			—
Other, net	896			2,356
Changes in operating assets and liabilities:
Accounts receivable	265			6,355
Other current assets	(1,109		)	(424		)
Accounts payable and accrued liabilities	(14,697		)	(11,538		)
Accrued interest and other	(53		)	27,260
Net cash provided by operating activities	34,322			93,559
Investing activities:
Capital expenditures for property and equipment:
Exploration, development, and leasehold acquisition costs	(101,665		)	(187,122		)
Other fixed assets	(268		)	(2,512		)
Proceeds from sales of assets	313,805			899
Net cash provided (used) by investing activities	211,872			(188,735		)
Financing activities:
Proceeds from bank borrowings	202,000			202,000
Repayments of bank borrowings	(127,000		)	(92,000		)
Redemption of senior notes	(321,315		)	—
Change in bank overdrafts	590			(17,284		)
Other, net	(300		)	325
Net cash (used) provided by financing activities	(246,025		)	93,041
Net increase (decrease) in cash and cash equivalents	169			(2,135		)
Cash and cash equivalents at beginning of period	1,056			3,012
Cash and cash equivalents at end of period	$	1,225		$	877
Cash paid during the period for:
Interest (net of capitalized amounts)	$	33,540		$	25,058
Income taxes (net of refunded amounts)	(129		)	(114		)
Non-cash investing activities:
Increase in accrued capital expenditures	$	26,303		$	5,444
Common stock issued for acquisition of unproved oil and natural gas properties	—			36,431

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) ORGANIZATION AND BASIS OF PRESENTATION

Organization

Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. Forest holds assets in several exploration and producing areas in the United States and has exploratory and development interests in two other countries. Unless the context indicates otherwise, the terms “Forest,” the “Company,” “we,” “our,” and “us,” as used in this Quarterly Report on Form 10-Q, refer to Forest Oil Corporation and its subsidiaries.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein are unaudited and include the accounts of Forest and its consolidated subsidiaries. All intercompany balances and transactions have been eliminated. In the opinion of management, all adjustments, which are of a normal recurring nature, have been made that are necessary for a fair presentation of the financial position of Forest at March 31, 2013, and the results of its operations, its comprehensive income, its cash flows, and changes in its shareholders’ equity for the periods presented. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in the prices of oil, natural gas, and natural gas liquids and the impact the prices have on Forest’s revenues and the fair values of its derivative instruments.

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

The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of oil, natural gas, and natural gas liquids reserves used in calculating depletion, the amount of future net revenues used in computing the ceiling test limitations, and the amount of future capital costs and abandonment obligations used in such calculations, assessing investments in unproved properties and goodwill for impairment, determining the need for and the amount of deferred tax asset valuation allowances, and estimating fair values of financial instruments, including derivative instruments.

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, 2012, previously filed with the Securities and Exchange Commission (“SEC”).

(2) EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share is computed using the two-class method by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. The two-class method of computing earnings (loss) per share is required to be used since Forest has participating securities. The two-class method is an earnings allocation formula that determines earnings (loss) per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Holders of restricted stock issued under Forest’s stock incentive plans have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock. Holders of phantom stock units issued to directors under Forest’s stock incentive plans also have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock, while phantom stock units issued to employees do not participate in dividends. Stock options issued under Forest’s stock incentive plans do not participate in dividends. Performance units issued under Forest’s stock incentive plans do not participate in dividends in their current form. Holders of performance units participate in dividends paid during the performance units’ vesting period only after the performance units vest and common shares are deliverable under the terms of the performance unit awards. Performance units may vest with no common shares being deliverable, depending on Forest’s shareholder return over the performance units’ vesting period in relation to the shareholder returns of specified peers. See Note 3 for more information on Forest’s stock-based incentive awards. In summary, restricted stock issued to employees and directors and phantom stock units issued to directors are participating securities, and earnings are allocated to both common

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stock and these participating securities under the two-class method. However, these participating securities do not have a contractual obligation to share in Forest’s losses. Therefore, in periods of net loss, none of the loss is allocated to these participating securities.

Diluted 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, increasing the denominator to include the number of additional common shares that would have been outstanding if the dilutive potential common shares (e.g. stock options, unvested restricted stock, unvested phantom stock units that may be settled in shares, and unvested performance units) had been issued. Additionally, the numerator is also adjusted for certain contracts that provide the issuer or holder with a choice between settlement methods. Diluted earnings per share is computed using the more dilutive of the treasury stock method or the two-class method. Under the treasury stock method, the dilutive effect of potential common shares is computed by assuming common shares are issued for these securities at the beginning of the period, with the assumed proceeds from exercise, which include average unamortized stock-based compensation costs, assumed to be used to purchase common shares at the average market price for the period, and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) included in the denominator of the diluted earnings per share computation. The number of contingently issuable shares pursuant to the outstanding performance units is included in the denominator of the computation of diluted earnings per share based on the number of shares, if any, that would be issuable if the end of the reporting period were the end of the contingency period and if the result would be dilutive. Under the two-class method, the dilutive effect of non-participating potential common shares is determined and undistributed earnings are reallocated between common shares and participating securities. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three months ended March 31, 2013 and 2012.

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



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Net loss	$	(67,948	)	$	(32,673	)
Less: net earnings attributable to participating securities	—			—
Net loss for basic and diluted loss per share	$	(67,948	)	$	(32,673	)

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



	Three Months Ended
	March 31,
	2013	2012
	(In Thousands)
Weighted average common shares outstanding during the period for basic loss per share	115,655	113,821
Dilutive effects of potential common shares	—	—
Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted loss per share	115,655	113,821

(3) STOCK-BASED COMPENSATION

Stock-based Compensation Plans

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

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Compensation Costs

The table below sets forth stock-based compensation for the three months ended March 31, 2013 and 2012, and the remaining unamortized amounts and weighted average amortization period as of March 31, 2013.



	Restricted Stock			Performance Units			Phantom Stock Units			Total⁽¹⁾⁽²⁾
	(In Thousands)
Three months ended March 31, 2013:
Total stock-based compensation costs	$	4,235		$	1,628		$	1,262		$	7,125
Less: stock-based compensation costs capitalized	(1,822		)	(473		)	(669		)	(2,964		)
Stock-based compensation costs expensed	$	2,413		$	1,155		$	593		$	4,161
Unamortized stock-based compensation costs⁽³⁾	$	19,905		$	6,188		$	10,106		$	36,199
Weighted average amortization period remaining	1.8 years			1.6 years			2.0 years			1.8 years
Three months ended March 31, 2012:
Total stock-based compensation costs	$	3,776		$	1,212		$	933		$	5,921
Less: stock-based compensation costs capitalized	(1,708		)	(390		)	(499		)	(2,597		)
Stock-based compensation costs expensed	$	2,068		$	822		$	434		$	3,324

____________________________________________


(1)	Forest also maintains an employee stock purchase plan (which is not included in the table) under which $.1 million of compensation cost was recognized for each of the three month periods ended March 31, 2013 and 2012.

(2)

In connection with the divestiture of the South Texas oil and natural gas properties during the three months ended March 31, 2013, Forest incurred one-time employee termination benefit costs that included $2.0 million ($1.0 million net of capitalized amounts) in stock-based compensation costs due to accelerated vesting of the affected awards. In addition to these stock-based compensation costs, during the three months ended March 31, 2013, Forest incurred $7.5 million ($5.7 million net of capitalized amounts) in other one-time employee termination benefit costs related to this divestiture. All of these one-time employee termination benefit costs expenses are included in “General and administrative” in the Condensed Consolidated Statement of Operations for the three months ended March 31, 2013 and no further one-time employee termination benefit costs are expected to be made for this specific divestiture. See Note 5 for more information regarding this divestiture.


(3)	The unamortized stock-based compensation costs of the phantom stock units are based on the closing price of Forest’s common stock at the reporting period end.

Stock Options

The following table summarizes stock option activity in the Plans for the three months ended March 31, 2013.



	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In Thousands)⁽¹⁾		Number of Options Exercisable
Outstanding at January 1, 2013	870,816		$	17.86	$	—	870,816
Granted	—		—
Exercised	—		—		—
Cancelled	(42,476	)	11.02
Outstanding at March 31, 2013	828,340		$	18.21	$	—	828,340

____________________________________________


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

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Restricted Stock, Performance Units, and Phantom Stock Units

The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Plans for the three months ended March 31, 2013.



	Restricted Stock						Performance Units						Phantom Stock Units
	Number of Shares		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)		Number of Units		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)		Number of Units⁽¹⁾		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)
Unvested at January 1, 2013	2,721,637		$	17.64			939,180		$	15.20			1,161,737		$	9.91
Awarded⁽²⁾	1,231,851		6.83				—		—				1,249,901		6.84
Vested	(220,475	)	19.61		$	1,479	(68,720	)	17.22		$	—	(90,821	)	10.49		$	615
Forfeited	(127,250	)	16.71				—		—				(63,586	)	10.38
Unvested at March 31, 2013	3,605,763		$	13.86			870,460		$	15.04			2,257,231		$	8.17

____________________________________________


(1)	All of the unvested units of phantom stock at March 31, 2013 must be settled in cash. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements. All of the phantom stock units that vested during the three months ended March 31, 2013 were settled in cash.


(2)	Forest granted 1,229,901 shares of restricted stock and 1,249,901 phantom stock units during the three months ended March 31, 2013 that vest in increments of 33.3% on each of the first three anniversary dates of the grant.

(4) DEBT

The components of debt are as follows:



	March 31, 2013								December 31, 2012
	Principal			Unamortized Premium		Total			Principal			Unamortized Premium (Discount)			Total
	(In Thousands)
Credit facility	$	140,000		$	—	$	140,000		$	65,000		$	—		$	65,000
7% senior subordinated notes due 2013	12			—		12			12			—			12
8½% senior notes due 2014⁽¹⁾	—			—		—			300,000			(3,277		)	296,723
7¼% senior notes due 2019	1,000,000			351		1,000,351			1,000,000			365			1,000,365
7½% senior notes due 2020	500,000			—		500,000			500,000			—			500,000
Total debt	1,640,012			351		1,640,363			1,865,012			(2,912		)	1,862,100
Less: current portion of long-term debt⁽²⁾	(12		)	—		(12		)	(12		)	—			(12		)
Long-term debt	$	1,640,000		$	351	$	1,640,351		$	1,865,000		$	(2,912	)	$	1,862,088

____________________________________________


(1)	In March 2013, Forest redeemed the 8½% senior notes due 2014 at 107.11% of par, recognizing a loss of $25.2 million upon redemption.


(2)	Due in June 2013.

Bank Credit Facility

As of March 31, 2013, the Company had a $1.5 billion credit facility (the “Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A. (the “Administrative Agent”), which matures in June 2016. The size of the Credit Facility may be increased by $300.0 million, to a total of $1.8 billion, upon agreement between the applicable lenders and Forest.

Forest’s availability under the Credit Facility is governed by a borrowing base. As of March 31, 2013, the borrowing base under the Credit Facility was $900.0 million. The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of Forest’s oil and gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. In addition to the scheduled semi-annual redeterminations, Forest and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined. The borrowing base is also subject to

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automatic adjustments if certain events occur, such as if Forest or any of its Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that Forest or any of its Restricted Subsidiaries may issue to refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if Forest or any of its Restricted Subsidiaries sell oil and natural gas properties included in the borrowing base, as applicable, having a fair market value in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount either (i) equal to the percentage of the borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by Forest and the required lenders. The February 2013 sale of Forest’s South Texas properties, discussed in Note 5, resulted in a $170.0 million reduction to the borrowing base effective February 15, 2013.

Effective April 12, 2013, the lenders completed the most recent scheduled semi-annual redetermination of the borrowing base, reaffirming it at $900.0 million. The next scheduled semi-annual redetermination of the borrowing base will occur on or about November 1, 2013. A lowering of the borrowing base could require Forest to repay indebtedness in excess of the borrowing base in order to cover the deficiency. The Credit Facility is collateralized by Forest’s assets, and Forest is required to mortgage and grant a security interest in 75% of the present value of the estimated proved oil and gas properties and related assets of Forest and its U.S. subsidiaries.

At March 31, 2013, there were outstanding borrowings of $140.0 million under the Credit Facility at a weighted average interest rate of 1.8% and Forest had used the Credit Facility for $1.6 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $758.4 million.

(5) PROPERTY AND EQUIPMENT

Full Cost Method of Accounting

The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which the Company has operations. During the periods presented, the Company’s primary oil and gas operations were conducted in the United States. 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, 2013 and 2012, Forest capitalized $12.3 million and $11.6 million, respectively, of general and administrative costs (including stock-based compensation). During the three months ended March 31, 2013 and 2012, Forest capitalized $.2 million and $2.2 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 at least annually to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, geographic and geologic data obtained relating to the properties, and estimated discounted future net cash flows from the properties. Estimated discounted future net cash flows are based on discounted future net revenues associated with probable and possible reserves, risk adjusted as appropriate. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.

The Company performs a ceiling test each quarter on a country-by-country basis under the full cost method of accounting. The ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or

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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.

Although Forest did not incur a ceiling test write-down during the three months ended March 31, 2013, ceiling test write-downs of the United States cost center may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenues from estimated production of proved oil and natural gas reserves declines compared to prices used as of March 31, 2013, unproved property values decrease, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center.

During the three months ended March 31, 2012, Forest recorded a $34.8 million ceiling test write-down of its Italian cost center due to an Italian regional regulatory body’s denial of approval of an environmental impact assessment associated with Forest’s proposal to commence natural gas production from wells that Forest drilled and completed in 2007. Forest is currently appealing the region’s denial; however, until the region’s denial is reversed or overturned, Forest determined that it could no longer conclude with reasonable certainty that its Italian natural gas reserves were producible and, therefore, reclassified the reserves from proved to probable, incurring a ceiling test write-down.

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

Depletion of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Company uses its quarter-end reserves estimates to calculate depletion for the current quarter.

Divestitures

In January 2013, Forest entered into an agreement to sell all of its oil and natural gas properties located in South Texas, excluding its Eagle Ford Shale oil properties, for $325.0 million in cash. This transaction closed on February 15, 2013 and was subject to customary purchase price adjustments, resulting in Forest receiving net proceeds of $307.2 million. Forest received an additional $13.8 million in April 2013 related to certain properties that required consents-to-assign that had not been received prior to the February 15, 2013 closing.

Asset Retirement Obligations

Forest records the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each period to its present value. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Forest’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

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The following table summarizes the activity for Forest’s asset retirement obligations for the period indicated:



	Three Months Ended March 31, 2013
	(In Thousands)
Asset retirement obligations at beginning of period	$	58,585
Accretion expense	1,244
Liabilities incurred	207
Liabilities settled	(953		)
Disposition of properties	(34,024		)
Revisions of estimated liabilities	76
Asset retirement obligations at end of period	25,135
Less: current asset retirement obligations	(1,436		)
Long-term asset retirement obligations	$	23,699

(6) INCOME TAXES

The significant differences between Forest’s blended federal and state statutory income tax rate of 36% and its effective income tax rates of (0.5)% and (2.9)% for the three months ended March 31, 2013 and 2012, respectively, were primarily due to changes in the valuation allowance on Forest’s deferred tax assets.

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

Negative evidence considered by Forest included a three-year cumulative book loss driven primarily by the ceiling test write-downs incurred in 2012. Positive evidence considered by Forest included forecasted book income in future periods based on expected future oil, natural gas, and NGL production and expected commodity prices based on NYMEX oil and natural gas futures. Based upon the evaluation of what was determined to be relevant evidence, Forest has recorded a valuation allowance against its deferred tax assets.

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(7) FAIR VALUE MEASUREMENTS

Forest’s assets and liabilities measured at fair value on a recurring basis at March 31, 2013 and December 31, 2012 are set forth in the table below.



	March 31, 2013		December 31, 2012
	Using Significant Other Observable Inputs (Level 2)⁽¹⁾
	(In Thousands)
Assets:
Derivative instruments⁽²⁾:
Commodity	$	3,964	$	35,465
Interest rate	9,910		13,060
Total assets	$	13,874	$	48,525
Liabilities:
Derivative instruments⁽²⁾:
Commodity	$	20,212	$	16,551
Interest rate	—		—
Total liabilities	$	20,212	$	16,551

____________________________________________

(1)

The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when relevant observable inputs are not available. There were no transfers between levels of the fair value hierarchy during the three months ended March 31, 2013. Forest’s policy is to recognize transfers between levels of the fair value hierarchy as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

(2)

Forest’s derivative assets and liabilities include commodity and interest rate derivatives (see Note 8 for more information on these instruments). Forest utilizes present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, Forest’s derivative instruments are included within the Level 2 fair value hierarchy.

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



	March 31, 2013
					Fair Value Measurements:
	Carrying Amount		Total Fair Value⁽¹⁾		Using Quoted Prices in Active Markets for Identical Assets (Level 1)		Using Significant Other Observable Inputs (Level 2)
	(In Thousands)
Assets:
Derivative instruments	$	13,874	$	13,874	$	—	$	13,874
Liabilities:
Derivative instruments	20,212		20,212		—		20,212
Credit facility	140,000		140,000		—		140,000
7¼% senior notes due 2019	1,000,351		1,022,000		1,022,000		—
7½% senior notes due 2020	500,000		529,375		529,375		—

__________________________________________

(1)

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

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	December 31, 2012
					Fair Value Measurements:
	Carrying Amount		Total Fair Value⁽¹⁾		Using Quoted Prices in Active Markets for Identical Assets (Level 1)		Using Significant Other Observable Inputs (Level 2)
	(In Thousands)
Assets:
Derivative instruments	$	48,525	$	48,525	$	—	$	48,525
Liabilities:
Derivative instruments	16,551		16,551		—		16,551
Credit facility	65,000		65,000		—		65,000
8½% senior notes due 2014	296,723		321,000		321,000		—
7¼% senior notes due 2019	1,000,365		1,006,850		1,006,850		—
7½% senior notes due 2020	500,000		526,250		526,250		—

__________________________________________

(1)

(8) DERIVATIVE INSTRUMENTS

Commodity Derivatives

Forest periodically enters into commodity derivative instruments such as swap and collar agreements as an attempt to moderate the effects of wide fluctuations in commodity prices on Forest’s cash flow and to manage the exposure to commodity price risk. Forest’s commodity derivative instruments generally serve as effective economic hedges of commodity price exposure; however, Forest has elected not to designate its derivatives as hedging instruments for accounting purposes. As such, Forest recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the Condensed Consolidated Statement of Operations.

The table below sets forth Forest’s outstanding commodity swaps as of March 31, 2013.



Commodity Swaps
	Natural Gas (NYMEX HH)			Oil (NYMEX WTI)
Remaining Term	Bbtu Per Day	Weighted Average Hedged Price per MMBtu		Barrels Per Day	Weighted Average Hedged Price per Bbl
April 2013 - December 2013	160	$	3.98	4,000	$	95.53
Calendar 2014	80	4.34		—	—

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In connection with several natural gas and oil swaps entered into, Forest granted swaptions to the swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas and oil swaps. These swaptions grant the swap counterparties the option to enter into future swaps with Forest and may not be exercised until their expiration dates. The table below sets forth the outstanding swaptions as of March 31, 2013.



Commodity Options
		Natural Gas (NYMEX HH)			Oil (NYMEX WTI)
Underlying Term	Option Expiration	Underlying Bbtu Per Day	Underlying Hedged Price per MMBtu		Underlying Barrels Per Day	Underlying Hedged Price per Bbl
Gas Swaptions:
Calendar 2014	December 2013	30	$	4.50	—	$	—
Calendar 2014	December 2013	10	4.51		—	—
Oil Swaptions:
Calendar 2014	December 2013	—	—		4,000	100.00
Calendar 2014	December 2013	—	—		1,000	109.00
Calendar 2015	December 2014	—	—		3,000	100.00

Interest Rate Derivatives

Forest has entered into interest rate derivative instruments in an attempt to manage the mix of fixed and floating interest rates within its debt portfolio. Forest has elected not to designate its derivatives as hedging instruments for accounting purposes. As such, Forest recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the Condensed Consolidated Statement of Operations. The table below sets forth Forest’s outstanding fixed-to-floating interest rate swaps as of March 31, 2013.



Interest Rate Swaps
Remaining Term	Notional Amount (In Thousands)		Weighted Average Floating Rate	Weighted Average Fixed Rate
April 2013 - February 2014	$	500,000	1 month LIBOR + 5.89%	8.50	%

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Fair Value and Gains and Losses

The table below summarizes the location and fair value amounts of Forest’s derivative instruments reported in the Condensed Consolidated Balance Sheets as of the dates indicated. These derivative instruments are not designated as hedging instruments for accounting purposes. For financial reporting purposes, Forest does not offset asset and liability fair value amounts recognized for derivative instruments with the same counterparty under its master netting arrangements. See “Credit Risk” below for more information regarding Forest’s master netting arrangements and gross and net presentation of derivative instruments. See also Note 7 for more information on the fair values of Forest’s derivative instruments.



	March 31, 2013		December 31, 2012
	(In Thousands)
Current assets:
Derivative instruments:
Commodity	$	184	$	28,690
Interest rate	9,910		11,500
Total current assets	$	10,094	$	40,190
Long-term assets:
Derivative instruments:
Commodity	$	3,780	$	6,775
Interest rate	—		1,560
Total long-term assets	$	3,780	$	8,335
Current liabilities:
Derivative instruments:
Commodity	$	15,772	$	9,347
Long-term liabilities:
Derivative instruments:
Commodity	$	4,440	$	7,204

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



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Commodity derivatives:
Realized gains	$	(9,649	)	$	(21,328	)
Unrealized losses (gains)	35,161			(6,446		)
Interest rate derivatives:
Realized gains	(3,082		)	(2,884		)
Unrealized losses	3,150			1,134
Realized and unrealized losses (gains) on derivative instruments, net	$	25,580		$	(29,524	)

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

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Credit Risk

Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. (“ISDA”) Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes, with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties’ requirements and the specific types of derivatives to be transacted. As of March 31, 2013, all but one of Forest’s derivative counterparties are lenders, or affiliates of lenders, under the Credit Facility. The terms of the Credit Facility provide that any security granted by Forest thereunder shall also extend to and be available to those lenders that are counterparties to derivative transactions. None of these counterparties requires collateral beyond that already pledged under the Credit Facility. The remaining counterparty, a purchaser of Forest’s natural gas production, generally owes money to Forest and therefore does not require collateral under the ISDA Master Agreement and Schedule it has executed with Forest.

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

The majority of Forest’s derivative counterparties are financial institutions that are engaged in similar activities and have similar economic characteristics that, in general, could cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions. Forest does not require the posting of collateral for its benefit under its derivative agreements. However, the ISDA Master Agreements and Schedules generally contain netting provisions whereby if on any date amounts would otherwise be payable by each party to the other, then on such date, the party that owes the larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party’s obligations. These provisions generally apply to all derivative transactions, or all derivative transactions of the same type (e.g., commodity, interest rate, etc.), with the particular counterparty. If all counterparties failed, Forest would be exposed to a risk of loss equal to this net amount owed to Forest, the fair value of which was $9.5 million at March 31, 2013. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net obligations due to it under the derivative agreements. At March 31, 2013, Forest owed a net derivative liability to its counterparties, the fair value of which was $15.9 million. In the absence of netting provisions, at March 31, 2013, Forest would be exposed to a risk of loss of $13.9 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $20.2 million.

For financial reporting purposes, Forest has elected to not offset asset and liability fair value amounts recognized for derivative instruments with the same counterparty under its master netting arrangements, although such derivative instruments are subject to enforceable master netting arrangements. The following tables disclose information regarding the potential effect of netting arrangements on Forest’s Condensed Consolidated Balance Sheets as of the dates indicated.



	Derivative Assets
	March 31, 2013			December 31, 2012
	(In Thousands)
Gross amounts of recognized assets	$	13,874		$	48,525
Gross amounts offset in the balance sheet	—			—
Net amounts of assets presented in the balance sheet	13,874			48,525
Gross amounts not offset in the balance sheet:
Derivative instruments	(4,345		)	(13,537		)
Cash collateral received	—			—
Net amount	$	9,529		$	34,988

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	Derivative Liabilities
	March 31, 2013			December 31, 2012
	(In Thousands)
Gross amounts of recognized liabilities	$	20,212		$	16,551
Gross amounts offset in the balance sheet	—			—
Net amounts of liabilities presented in the balance sheet	20,212			16,551
Gross amounts not offset in the balance sheet:
Derivative instruments	(4,345		)	(13,537		)
Cash collateral pledged	—			—
Net amount	$	15,867		$	3,014

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

(9) COSTS, EXPENSES, AND OTHER

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



	Three Months Ended
	March 31,
	2013		2012
	(In Thousands)
Accretion of asset retirement obligations	$	1,244	$	1,598
Loss on debt extinguishment	25,223		—
Legal proceeding liabilities	—		22,847
Other, net	2,353		2,475
	$	28,820	$	26,920

Accretion of Asset Retirement Obligations

Accretion of asset retirement obligations is the expense recognized to increase the carrying amount of the liability associated with our asset retirement obligations as a result of the passage of time. 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 natural gas properties.

Loss on Debt Extinguishment

In March 2013, Forest redeemed $300.0 million in principal amount of 8½% senior notes at 107.11% of par, recognizing a loss of $25.2 million upon redemption due to the $21.3 million call premium and write-off of $3.9 million of unamortized discount and debt issue costs.

Legal Proceeding Liabilities

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled Forest Oil Corporation, et al. v. El Rucio Land & Cattle Company, Inc., et al., which occurred in Harris County, Texas. The third member of the arbitration panel dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration decision awards the claimant $22.8 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use

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issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55^th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest is seeking to have this judgment reversed on appeal and believes it has meritorious arguments in support thereof. However, Forest is unable to predict the final outcome in this matter and has accrued a liability, which is classified within “Other liabilities” in the Condensed Consolidated Balance Sheet, of $23.3 million, which includes accrued interest, for this matter.

(10) COMPREHENSIVE INCOME (LOSS)

Comprehensive income (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) during the three months ended March 31, 2013 are actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost.

The components of other comprehensive income (loss), both before-tax and net-of-tax, for the three months ended March 31, 2013 are as follows:



	Before-Tax		Tax (Expense) / Benefit		Net-of-Tax
	(In Thousands)
Three Months Ended March 31, 2013:
Defined benefit postretirement plans
Net periodic benefit cost components arising during the period	$	—	$	—	$	—
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost	342		—		342
Other comprehensive income	$	342	$	—	$	342

The change in the accumulated balance of other comprehensive income (loss) during the three months ended March 31, 2013 is as follows:



	Accumulated Other Comprehensive Income (Loss)⁽¹⁾
	(In Thousands)
Defined benefit postretirement plans
Balance at December 31, 2012	$	(20,514	)

Other comprehensive income (loss) arising during the period, before reclassifications	—
Amounts reclassified from accumulated other comprehensive loss	342
Other comprehensive income	342

Balance at March 31, 2013	$	(20,172	)

____________________________________


(1)	All amounts are net of tax.

(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Company’s 7¼% senior notes due 2019 and 7½% senior notes due 2020 have been fully and unconditionally guaranteed by a 100%-owned subsidiary of the Company (the “Guarantor Subsidiary”). The Company’s remaining subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The Guarantor Subsidiary’s guarantee may be released automatically under the following customary circumstances:


•	in connection with any sale or other disposition of all or substantially all of the property of the Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) a restricted subsidiary of the Company;


•	in connection with any sale or other disposition of the capital stock of the Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) a restricted subsidiary of the Company;


•	if the Company designates that Guarantor Subsidiary as an unrestricted subsidiary in accordance with the applicable provisions of the indentures;


•	if the Company exercises its legal defeasance option or its covenant defeasance option or upon satisfaction and discharge of the indentures; or


•	at such time as such Guarantor Subsidiary ceases to guarantee any other indebtedness of the Company, provided that at such time it does not have outstanding an aggregate of $25.0 million or more of indebtedness and preferred stock.

The following presents condensed consolidating financial information as of March 31, 2013 and December 31, 2012, and for the three months ended March 31, 2013 and 2012 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Eliminating entries presented are necessary to combine the entities.

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

(In Thousands)



	March 31, 2013														December 31, 2012
	Parent Company			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent Company			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	988		$	12	$	225		$	—		$	1,225		$	667		$	45	$	344		$	—		$	1,056
Accounts receivable	53,968			23,234		5,294			(617		)	81,879			33,979			27,969		6,393			(825		)	67,516
Other current assets	26,310			287		361			—			26,958			55,869			286		353			—			56,508
Total current assets	81,266			23,533		5,880			(617		)	110,062			90,515			28,300		7,090			(825		)	125,080
Property and equipment, at cost	8,200,878			1,432,156		177,967			—			9,811,001			8,439,898			1,416,364		182,070			—			10,038,332
Less accumulated depreciation, depletion, and amortization	6,974,464			1,184,181		173,857			—			8,332,502			6,937,606			1,173,332		173,156			—			8,284,094
Net property and equipment	1,226,414			247,975		4,110			—			1,478,499			1,502,292			243,032		8,914			—			1,754,238
Investment in subsidiaries	76,919			—		—			(76,919		)	—			68,048			—		—			(68,048		)	—
Goodwill	216,460			22,960		—			—			239,420			216,460			22,960		—			—			239,420
Due from subsidiaries	105,626			92,333		—			(197,959		)	—			116,602			83,983		—			(200,585		)	—
Deferred income taxes	100,484			—		36,106			(132,440		)	4,150			111,015			—		36,106			(132,440		)	14,681
Other assets	62,853			—		—			—			62,853			68,443			—		—			—			68,443
	$	1,870,022		$	386,801	$	46,096		$	(407,935	)	$	1,894,984		$	2,173,375		$	378,275	$	52,110		$	(401,898	)	$	2,201,862
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	174,721		$	1,037	$	6,038		$	(617	)	$	181,179		$	157,404		$	2,133	$	6,074		$	(825	)	$	164,786
Other current liabilities	50,394			—		6,270			—			56,664			55,187			67		6,285			—			61,539
Total current liabilities	225,115			1,037		12,308			(617		)	237,843			212,591			2,200		12,359			(825		)	226,325
Long-term debt	1,640,351			—		—			—			1,640,351			1,862,088			—		—			—			1,862,088
Due to parent and subsidiaries	—			—		197,959			(197,959		)	—			—			—		200,585			(200,585		)	—
Deferred income taxes	—			132,440		—			(132,440		)	—			—			132,440		—			(132,440		)	—
Other liabilities	109,307			2,656		9,578			—			121,541			141,520			3,642		11,111			—			156,273
Total liabilities	1,974,773			136,133		219,845			(331,016		)	1,999,735			2,216,199			138,282		224,055			(333,850		)	2,244,686
Shareholders’ equity (deficit)	(104,751		)	250,668		(173,749		)	(76,919		)	(104,751		)	(42,824		)	239,993		(171,945		)	(68,048		)	(42,824		)
	$	1,870,022		$	386,801	$	46,096		$	(407,935	)	$	1,894,984		$	2,173,375		$	378,275	$	52,110		$	(401,898	)	$	2,201,862

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In Thousands)



	Three Months Ended March 31,
	2013															2012
	Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil, natural gas, and natural gas liquids sales	$	92,537		$	25,030		$	475		$	—		$	118,042		$	106,823		$	51,606		$	472		$	—		$	158,901
Interest and other	225			402			—			(495		)	132			778			1,959			—			(2,705		)	32
Equity earnings in subsidiaries	4,146			—			—			(4,146		)	—			(16,794		)	—			—			16,794			—
Total revenues	96,908			25,432			475			(4,641		)	118,174			90,807			53,565			472			14,089			158,933
Costs, expenses, and other:
Lease operating expenses	17,945			3,175			84			—			21,204			23,819			3,688			100			—			27,607
Other production expenses	5,921			(465		)	40			—			5,496			13,797			1,277			51			—			15,125
General and administrative	19,131			670			213			—			20,014			14,364			731			289			—			15,384
Depreciation, depletion, and amortization	37,562			10,848			133			—			48,543			47,869			18,668			433			—			66,970
Ceiling test write-down of natural gas properties	—			—			—			—			—			—			—			34,817			—			34,817
Interest expense	36,128			32			463			(495		)	36,128			33,392			1,711			994			(2,705		)	33,392
Realized and unrealized losses (gains) on derivative instruments, net	20,865			4,675			40			—			25,580			(24,607		)	(4,847		)	(70		)	—			(29,524		)
Other, net	27,010			117			1,693			—			28,820			25,232			90			1,598			—			26,920
Total costs, expenses, and other	164,562			19,052			2,666			(495		)	185,785			133,866			21,318			38,212			(2,705		)	190,691
Earnings (loss) before income taxes	(67,654		)	6,380			(2,191		)	(4,146		)	(67,611		)	(43,059		)	32,247			(37,740		)	16,794			(31,758		)
Income tax	294			32			11			—			337			(10,386		)	12,428			(1,127		)	—			915
Net earnings (loss)	$	(67,948	)	$	6,348		$	(2,202	)	$	(4,146	)	$	(67,948	)	$	(32,673	)	$	19,819		$	(36,613	)	$	16,794		$	(32,673	)
Comprehensive income (loss)	$	(67,606	)	$	6,348		$	(2,202	)	$	(4,146	)	$	(67,606	)	$	(32,486	)	$	19,819		$	(36,613	)	$	16,794		$	(32,486	)

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)



	Three Months Ended March 31,
	2013												2012
	Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidated			Parent Company			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidated
Operating activities:
Net earnings (loss)	$	(72,094	)	$	6,348		$	(2,202	)	$	(67,948	)	$	(15,879	)	$	19,819		$	(36,613	)	$	(32,673	)
Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	37,562			10,848			133			48,543			47,869			18,668			433			66,970
Deferred income tax	—			—			—			—			(10,168		)	12,428			(1,127		)	1,133
Unrealized losses (gains) on derivative instruments, net	31,813			6,443			55			38,311			(4,171		)	(1,125		)	(16		)	(5,312		)
Ceiling test write-down of natural gas properties	—			—			—			—			—			—			34,817			34,817
Loss on debt extinguishment	25,223			—			—			25,223			—			—			—			—
Other, net	6,808			113			(1,134		)	5,787			7,354			87			(470		)	6,971
Changes in operating assets and liabilities:
Accounts receivable	(5,361		)	4,735			891			265			8,230			(2,022		)	147			6,355
Other current assets	(2,228		)	(1		)	1,120			(1,109		)	(341		)	(1		)	(82		)	(424		)
Accounts payable and accrued liabilities	(14,279		)	(585		)	167			(14,697		)	(11,062		)	(1,441		)	965			(11,538		)
Accrued interest and other	52			(90		)	(15		)	(53		)	25,174			2,545			(459		)	27,260
Net cash provided (used) by operating activities	7,496			27,811			(985		)	34,322			47,006			48,958			(2,405		)	93,559
Investing activities:
Capital expenditures for property and equipment	(84,681		)	(16,962		)	(290		)	(101,933		)	(143,394		)	(43,102		)	(3,138		)	(189,634		)
Proceeds from sales of assets	313,803			—			2			313,805			899			—			—			899
Net cash provided (used) by investing activities	229,122			(16,962		)	(288		)	211,872			(142,495		)	(43,102		)	(3,138		)	(188,735		)
Financing activities:
Proceeds from bank borrowings	202,000			—			—			202,000			202,000			—			—			202,000
Repayments of bank borrowings	(127,000		)	—			—			(127,000		)	(92,000		)	—			—			(92,000		)
Redemption of senior notes	(321,315		)	—			—			(321,315		)	—			—			—			—
Change in bank overdrafts	882			(416		)	124			590			(17,510		)	(253		)	479			(17,284		)
Net activity in investments in subsidiaries	8,251			(10,466		)	2,215			—			1,617			(5,600		)	3,983			—
Other, net	885			—			(1,185		)	(300		)	325			—			—			325
Net cash (used) provided by financing activities	(236,297		)	(10,882		)	1,154			(246,025		)	94,432			(5,853		)	4,462			93,041
Net increase (decrease) in cash and cash equivalents	321			(33		)	(119		)	169			(1,057		)	3			(1,081		)	(2,135		)
Cash and cash equivalents at beginning of period	667			45			344			1,056			1,734			1			1,277			3,012
Cash and cash equivalents at end of period	$	988		$	12		$	225		$	1,225		$	677		$	4		$	196		$	877

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

OVERVIEW

All expectations, forecasts, assumptions, and beliefs about our future financial results, condition, operations, strategic plans, and performance are forward-looking statements, as described in more detail under the heading “Forward-Looking Statements” below. Our actual results may differ materially because of a number of risks and uncertainties. Historical statements made herein are accurate only as of the date of filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”), and may be relied upon only as of that date. The following discussion and analysis should be read in conjunction with Forest’s Condensed Consolidated Financial Statements and the Notes thereto, the information included or incorporated by reference under the headings “Forward-Looking Statements” and “Risk Factors” below, and the information included or incorporated by reference in Forest’s 2012 Annual Report on Form 10-K under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Unless the context indicates otherwise, all references in this document to “Forest,” “the Company,” “we,” “our,” “ours,” and “us” refer to Forest Oil Corporation and its consolidated subsidiaries.

Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. We currently conduct our operations in one material geographical segment: the United States. Our core operational areas are in the Texas Panhandle Area, the Eagle Ford Shale in South Texas, and the East Texas / North Louisiana Area.

Recent Events

In October 2012, we entered into an agreement to sell all of our oil and natural gas properties located in South Louisiana for $220 million in cash. This transaction closed on November 16, 2012 and we received net proceeds of $208 million after customary purchase price adjustments. In January 2013, we entered into an agreement to sell all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford Shale oil properties, for $325 million in cash. This transaction closed on February 15, 2013 and we received net proceeds of $307 million after customary purchase price adjustments. We received an additional $14 million in April 2013 related to certain properties that required consents-to-assign that had not been received prior to the February 15, 2013 closing. We used the proceeds from these property sales to pay down debt. These property sales affect the comparability of the results of our operations between the three months ended March 31, 2013 and the three months ended March 31, 2012 presented herein.

In April 2013, we entered into an agreement with Schlumberger for the future development of our Eagle Ford Shale acreage in Gonzales County, Texas. Under the terms of the agreement, Schlumberger will pay a $90 million drilling carry in the form of future drilling and completion services and related development capital in exchange for a 50% working interest in our Eagle Ford Shale acreage position. Upon completion of the phased contribution of the drilling carry, Forest and Schlumberger will participate in future drilling on a 50/50 basis. The agreement applies to wells spud on or subsequent to November 28, 2012, none of which had been placed on production prior to April 1, 2013, and we will retain all of our interests in wells and production that have been spud prior to November 28, 2012. We will be the operator of the drilling program and currently expect that the drilling carry will be fully realized by the end of 2014. As part of the agreement, Schlumberger will provide us assistance in the development and production enhancement of our Eagle Ford acreage in the form of integrated service offerings and asset management support, including but not limited to, drilling, completion, lifting, and reservoir management technologies, and development of unconventional resources workflows.

RESULTS OF OPERATIONS

For the three months ended March 31, 2013, we recognized a net loss of $68 million, which included a $38 million unrealized loss on derivative instruments, a $25 million loss on the early termination of debt, and $7 million in severance-related expense associated with the sale of our South Texas oil and natural gas properties in the first quarter of 2013. For the three months ended March 31, 2012, we recognized a net loss of $33 million, which included a $35 million ceiling test write-down of our Italian natural gas properties and $23 million in expense related to legal proceedings.

Adjusted EBITDA, which excludes the effects of unrealized gains and losses on derivative instruments, ceiling test write-downs, and other items, was $94 million for the three months ended March 31, 2013 as compared to $126 million for the three months ended March 31, 2012. The $31 million decrease between the corresponding periods was primarily due to a $41 million decrease in oil, natural gas, and natural gas liquids revenues and an $11 million decrease in realized gains on derivative

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instruments, partially offset by a $16 million decrease in production expense. Oil, natural gas, and natural gas liquids revenues and production costs each decreased as compared to the three months ended March 31, 2012 due primarily to the sales of oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively. Adjusted EBITDA is a performance measure that is not calculated in accordance with generally accepted accounting principles (“GAAP”); see “—Reconciliation of Non-GAAP Measure” at the end of this Item 2 for a reconciliation of Adjusted EBITDA to reported net loss, which is the most directly comparable financial measure calculated and presented in accordance with GAAP.

Management’s analysis of the individual components of the changes in our quarterly results follows.

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

Oil, natural gas, and natural gas liquids sales volumes, revenues, and average sales prices for the three months ended March 31, 2013 and 2012 are set forth in the table below.



	Three Months Ended
	March 31,
	2013		2012
Sales volumes:
Oil (MBbls)	559		767
Natural gas (MMcf)	14,332		20,893
NGLs (MBbls)	698		866
Totals (MMcfe)	21,874		30,691
Revenues (in thousands):
Oil	$	53,962	$	79,451
Natural gas	42,658		48,028
NGLs	21,422		31,422
Totals	$	118,042	$	158,901
Average sales price per unit:
Oil ($/Bbl)	$	96.53	$	103.59
Natural gas ($/Mcf)	2.98		2.30
NGLs ($/Bbl)	30.69		36.28
Totals ($/Mcfe)	$	5.40	$	5.18

Our equivalent sales volumes for the three months ended March 31, 2013 were 21.9 Bcfe compared to 30.7 Bcfe in the corresponding period in 2012. The 29% decrease was primarily due to divestitures of oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively. Revenues from oil, natural gas, and NGLs were $118 million in the first quarter of 2013 compared to $159 million in the first quarter of 2012. The $41 million, or 26%, decrease was also primarily a result of the decrease in equivalent sales volumes due to the aforementioned divestitures. The decrease due to the decline in equivalent sales volumes was partially offset by a 4% increase in the average sales price per Mcfe between the two periods from $5.18 per Mcfe in the first quarter of 2012 to $5.40 per Mcfe in the first quarter of 2013.

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The revenues and average sales prices reflected in the table above exclude the effects of commodity derivative instruments because we have elected not to designate our derivative instruments as cash flow hedges. The table below shows the average realized price per unit including the effects of the commodity derivative instruments we had in place for the periods presented.



	Three Months Ended
	March 31,
	2013		2012
Oil:
Average sales price ($/Bbl)	$	96.53	$	103.59
Effects of commodity derivatives ($/Bbl)	.77		(2.79		)
Average realized price ($/Bbl)	$	97.30	$	100.80

Natural gas:
Average sales price ($/Mcf)	$	2.98	$	2.30
Effects of commodity derivatives ($/Mcf)	.64		1.17
Average realized price ($/Mcf)	$	3.62	$	3.47

NGLs:
Average sales price ($/Bbl)	$	30.69	$	36.28
Effects of commodity derivatives ($/Bbl)	—		(1.12		)
Average realized price ($/Bbl)	$	30.69	$	35.16

Totals:
Average sales price ($/Mcfe)	$	5.40	$	5.18
Effects of commodity derivatives ($/Mcfe)	.44		.69
Average realized price ($/Mcfe)	$	5.84	$	5.87

See “Realized and Unrealized Gains and Losses on Derivative Instruments” below for more information on gains and losses relating to our commodity derivative instruments.

Production Expense

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



	Three Months Ended
	March 31,
	2013		2012
	(In Thousands, Except Per Mcfe Data)
Production expense:
Lease operating expenses	$	21,204	$	27,607
Production and property taxes	2,216		11,153
Transportation and processing costs	3,280		3,972
Production expense	$	26,700	$	42,732
Production expense per Mcfe:
Lease operating expenses	$	.97	$	.90
Production and property taxes	.10		.36
Transportation and processing costs	.15		.13
Production expense per Mcfe	$	1.22	$	1.39

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Lease Operating Expenses

Lease operating expenses in the first quarter of 2013 were $21 million, or $.97 per Mcfe, compared to $28 million, or $.90 per Mcfe, in the first quarter of 2012. Lease operating expenses decreased $6 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 primarily due to the oil and natural gas property divestitures that occurred in November 2012 and February 2013.

Production and Property Taxes

Production and property taxes, consisting primarily of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 1.9% and 7.0% of oil, natural gas, and NGL revenues for the three-month periods ended March 31, 2013 and 2012, respectively. The decrease in production and property taxes as a percentage of revenues in the first quarter of 2013 was due to reduced severance tax rates on several wells in the Texas Panhandle Area. Normal fluctuations occur in this percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, and changes in the assessed values of oil and gas properties and equipment for purposes of ad valorem taxes.

Transportation and Processing Costs

Transportation and processing costs in the first quarter of 2013 were $3 million, or $.15 per Mcfe, compared to $4 million, or $.13 per Mcfe, in the first quarter of 2012.

General and Administrative Expense

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



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Stock-based compensation costs	$	7,224		$	6,047
Stock-based compensation costs capitalized	(2,964		)	(2,597		)
	4,260			3,450

Other general and administrative costs	25,088			20,888
Other general and administrative costs capitalized	(9,334		)	(8,954		)
	15,754			11,934

General and administrative expense	$	20,014		$	15,384

General and administrative expense was $20 million in the first quarter of 2013 compared to $15 million in the first quarter of 2012. The increase in other general and administrative costs in the first quarter of 2013 was due to $8 million ($6 million net of capitalized amounts) in severance-related costs incurred in the first quarter of 2013. These one-time employee termination benefit costs were incurred due to the disposition of the South Texas oil and natural gas properties during the quarter. Stock-based compensation costs also include severance-related costs totaling $2 million ($1 million net of capitalized amounts) in the first quarter of 2013. The percentage of general and administrative costs capitalized under the full cost method of accounting ranged from 38% to 43% in the periods presented.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization expense (“DD&A”) in the first quarter of 2013 was $49 million, or $2.22 per Mcfe, compared to $67 million, or $2.18 per Mcfe, in the first quarter of 2012.

Ceiling Test Write-Down of Oil and Natural Gas Properties

In April 2012, an Italian regional regulatory body denied approval of an environmental impact assessment associated with our proposal to commence natural gas production from wells that we drilled and completed in 2007. We are currently appealing the region’s denial; however, until the region’s denial is reversed or overturned, we determined that we could no

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longer conclude with reasonable certainty that our Italian natural gas reserves are producible. Accordingly, in the first quarter of 2012, we reclassified the Italian reserves from proved to probable and recorded a ceiling test write-down of our Italian cost center of $35 million.

Interest Expense

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



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Interest costs	$	36,319		$	35,621
Interest costs capitalized	(191		)	(2,229		)
Interest expense	$	36,128		$	33,392

Interest expense was $36 million in the first quarter of 2013 compared to $33 million in the first quarter of 2012. The increase of $3 million was primarily attributable to interest costs on the $500 million of 7½% senior notes issued in September 2012 and lower capitalized interest in 2013, partially offset by the redemption of $300 million of 8½% senior notes in October 2012 and the redemption of the remaining $300 million of 8½% senior notes in March 2013. Interest costs capitalized relate to our investments in significant unproved acreage positions that are under development.

In order to effectively reduce our concentration of fixed-rate debt, we have entered into fixed-to-floating interest rate swaps under which we have swapped, as of March 31, 2013, $500 million in notional amount at an 8.5% fixed rate for an equal notional amount at a weighted-average interest rate equal to the 1-month LIBOR plus approximately 5.9%. We recognized realized gains under these interest rate swaps of $3 million during both of the three month periods ended March 31, 2013 and 2012. These gains are recorded as realized gains on derivatives rather than as a reduction in interest expense since we have not elected to use hedge accounting. See Note 8 to the Condensed Consolidated Financial Statements for more information on our interest rate derivatives.

Realized and Unrealized Gains and Losses on Derivative Instruments

The table below sets forth realized and unrealized gains and losses on derivative instruments recognized under “Costs, expenses, and other” in our Condensed Consolidated Statements of Operations for the periods indicated. See Note 7 and Note 8 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Realized (gains) losses on derivative instruments, net:
Oil	$	(428	)	$	2,140
Natural gas	(9,221		)	(24,441		)
NGLs	—			973
Interest	(3,082		)	(2,884		)
Subtotal realized gains on derivative instruments, net	(12,731		)	(24,212		)
Unrealized (gains) losses on derivative instruments, net:
Oil	(308		)	17,399
Natural gas	35,469			(20,520		)
NGLs	—			(3,325		)
Interest	3,150			1,134
Subtotal unrealized losses (gains) on derivative instruments, net	38,311			(5,312		)
Realized and unrealized losses (gains) on derivative instruments, net	$	25,580		$	(29,524	)

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Other, Net

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



	Three Months Ended
	March 31,
	2013		2012
	(In Thousands)
Accretion of asset retirement obligations	$	1,244	$	1,598
Loss on debt extinguishment	25,223		—
Legal proceeding liabilities	—		22,847
Other, net	2,353		2,475
	$	28,820	$	26,920

See Note 9 to the Condensed Consolidated Financial Statements for more information on the components of “Other, net”.

Income Tax

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



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands, Except Percentages)
Current income tax	$	337		$	(218	)
Deferred income tax	—			1,133
Total income tax	$	337		$	915
Effective income tax rate	(0.5		)%	(3		)%

Our effective income tax rates were (0.5)% and (3)% for the three months ended March 31, 2013 and 2012, respectively. The significant differences between our blended federal and state statutory income tax rate of 36% and our effective income tax rates of (0.5)% and (3)% for the three months ended March 31, 2013 and 2012, respectively, were primarily due to valuation allowances placed against our deferred tax assets. See Note 6 to the Condensed Consolidated Financial Statements for more information regarding our income tax 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 facility as our primary sources of liquidity. To fund large transactions, such as acquisitions and debt refinancing transactions, we have looked to the private and public capital markets as another source of financing and, as market conditions have permitted, we have engaged in asset monetization transactions.

Changes in the market prices for oil, natural gas, and natural gas liquids directly impact our level of cash flow generated from operations. For the three months ended March 31, 2013, natural gas accounted for approximately 66% of our total production and, as a result, our operations and cash flow are more sensitive to fluctuations in the market price for natural gas than to fluctuations in the market prices for oil and natural gas liquids. We employ a commodity hedging strategy in an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of May 2, 2013, we had hedged, via commodity swaps, approximately 67 Bcfe of our total projected 2013 production and approximately 29 Bcf of our total projected 2014 production, excluding the volumes underlying outstanding unexercised commodity swaptions. This level of hedging will provide a measure of certainty with respect to the cash flow that we will receive for a portion of our future production. However, these hedging activities may result in reduced income or even financial losses to us. In the future, we may determine to increase or decrease our hedging positions. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” below for more information on our derivative instruments.

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As noted above, the other primary source of liquidity is our bank credit facility, which currently has a borrowing base of $900 million. The borrowing base is subject to redetermination from time to time as discussed below under “Bank Credit Facility”. This facility is used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facility is secured by a portion of our assets and matures in June 2016. The credit facility contains a covenant that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.5 to 1.0 at any time. Depending on our overall level of indebtedness, this covenant may limit our ability to borrow funds as needed under our credit facility. Our ratio of total debt outstanding to EBITDA for the twelve-month period ended March 31, 2013, as calculated in accordance with our credit facility, was 4.3. We had $140 million and $154 million of borrowings outstanding under our credit facility as of March 31, 2013 and May 2, 2013, respectively. See “Bank Credit Facility” below for further details regarding the Credit Facility.

The public and private capital markets have served as our primary source of financing to fund large acquisitions and other exceptional transactions, such as debt refinancings. In the past, we have issued debt and equity in both the public and private capital markets. Our ability to access the debt and equity capital markets on economic terms is affected by general economic conditions, the domestic and global financial markets, the credit ratings assigned to our debt by independent credit rating agencies, our operational and financial performance, the value and performance of our equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

We also have engaged in asset dispositions as a means of generating additional cash to fund expenditures and enhance our financial flexibility. For example, in November 2012, we sold all of our oil and natural gas properties located in South Louisiana for net proceeds of $208 million. Additionally, in February 2013 we sold all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford Shale oil properties, for net proceeds of $307 million (not including an additional $14 million received in April 2013), which we used in March 2013 to redeem $300 million in principal amount of 8½% senior notes due 2014.

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

Bank Credit Facility

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

Our availability under the Credit Facility is governed by a borrowing base. As of March 31, 2013, the borrowing base under the Credit Facility was $900 million. The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil and gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. A lowering of the borrowing base could require us to repay indebtedness in excess of the borrowing base in order to cover the deficiency. The lenders completed their most recent scheduled semi-annual redetermination of the borrowing base, reaffirming it at $900 million effective April 12, 2013. The next scheduled semi-annual redetermination of the borrowing base will occur on or about November 1, 2013. In addition to the scheduled semi-annual redeterminations, we and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined.

The borrowing base is also subject to automatic adjustments if certain events occur, such as if we or any of our Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that we or any of our Restricted Subsidiaries may issue to refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if we or any of our Restricted Subsidiaries sell oil and natural gas properties included in the borrowing base, as applicable, having a fair market value in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount either (i) equal to the percentage of the borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by us and the required lenders. The sale of our South Texas properties resulted in a $170 million reduction to the borrowing base when the transaction closed in February 2013,

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bringing the borrowing base to $900 million. See Note 5 to the Condensed Consolidated Financial Statements for more information regarding this divestiture.

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

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

(i)

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


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

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant. The Credit Facility provides that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.5 to 1.0 at any time. Our ratio of total debt outstanding to EBITDA for the twelve-month period ended March 31, 2013, as calculated in accordance with the Credit Facility, was 4.3. We expect to continue to meet this covenant by maintaining our capital expenditures at levels that approximate our cash flows from operating activities and by using proceeds from the sale of non-core assets to reduce debt.

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

At March 31, 2013, there were outstanding borrowings of $140 million under the Credit Facility at a weighted average interest rate of 1.8% and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $758 million. At May 2, 2013, there were outstanding borrowings of $154 million under the Credit Facility at a weighted average interest rate of 1.8%, and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $744 million.

Of the $1.5 billion total nominal amount under the Credit Facility, JPMorgan and ten other banks hold approximately 68% of the total commitments. With respect to the other 32% of the total commitments, no single lender holds more than 3.3% of the total commitments. Commitment fees accrue on the amount of unutilized borrowing base. If borrowing base utilization is greater than 50%, commitment fees are 50 basis points of the unutilized amount, and if borrowing base utilization is 50% or less, commitment fees are 35 basis points of the unutilized amount.

We engage in other transactions with a number of the lenders under the Credit Facility. Such lenders or their affiliates may serve as underwriters or initial purchasers of our debt and equity securities, or directly purchase our production, or serve as counterparties to our commodity and interest rate derivative agreements. As of May 2, 2013, all but one of our derivative instrument counterparties are lenders, or their affiliates, under our Credit Facility. Our obligations under our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our Credit Facility. See Item 3, ‘‘Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk’’ below for additional details concerning our derivative instruments.

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Historical Cash Flow

Net cash provided by operating activities, net cash provided (used) by investing activities, and net cash (used) provided by financing activities for the three months ended March 31, 2013 and 2012 were as follows:



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Net cash provided by operating activities	$	34,322		$	93,559
Net cash provided (used) by investing activities	211,872			(188,735		)
Net cash (used) provided by financing activities	(246,025		)	93,041

Net cash provided by operating activities is primarily affected by sales volumes and commodity prices, net of the effects of settlements of our derivative instruments and changes in working capital. The decrease in net cash provided by operating activities in the three months ended March 31, 2013 compared to the three months ended March 31, 2012, was primarily due to decreased revenues, which was caused by lower sales volumes. The decrease was also due to lower realized gains on derivative instruments, higher general and administrative expense due to one-time employee termination benefit costs, and an increased investment in net operating assets (i.e., working capital), partially offset by lower production expense.

The components of net cash provided (used) by investing activities for the three months ended March 31, 2013 and 2012 were as follows:



	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Exploration, development, and leasehold acquisition costs⁽¹⁾	$	(101,665	)	$	(187,122	)
Proceeds from sale of assets	313,805			899
Other fixed asset costs	(268		)	(2,512		)
Net cash provided (used) by investing activities	$	211,872		$	(188,735	)

____________________________________________

(1)

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

Net cash provided (used) by investing activities is primarily comprised of expenditures for the acquisition, exploration, and development of oil and natural gas properties, net of proceeds from the dispositions of oil and natural gas properties and other capital assets. The increase in net cash provided by investing activities in the three months ended March 31, 2013 compared to the corresponding period of 2012 was primarily due to an increase in proceeds from the sale of assets, due to the South Texas disposition in February 2013, as well as a decrease in exploration, development, and leasehold acquisition cost expenditures during the three months ended March 31, 2013.

Net cash used by financing activities increased by $339 million from $93 million in net cash provided by financing activities in the three months ended March 31, 2012 to $246 million in net cash used by financing activities in the three months ended March 31, 2013. This increase in net cash used by financing activities was primarily due to the redemption of the 8½% senior notes due 2014 for $321 million in March 2013. This use of cash by financing activities was partially offset by net proceeds from bank borrowings of $75 million during the three months ended March 31, 2013. Net cash provided by financing activities in the three months ended March 31, 2012 primarily consisted of net proceeds from bank borrowings of $110 million.

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Capital Expenditures

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



	Three Months Ended
	March 31,
	2013		2012
	(In Thousands)
Exploration, development, and acquisition costs:
Direct costs:
Exploration and development	$	115,823	$	173,781
Leasehold acquisitions	2,605		44,855
Overhead capitalized	12,298		11,551
Interest capitalized	191		2,229
Total capital expenditures⁽¹⁾	$	130,917	$	232,416

____________________________________________

(1)

Total capital expenditures include cash expenditures, accrued expenditures, and non-cash capital expenditures including the value of common stock issued for oil and natural gas property acquisitions and stock-based compensation capitalized under the full cost method of accounting. Total capital expenditures also include changes in estimated discounted asset retirement obligations of $.3 million and $1 million recorded during the three months ended March 31, 2013 and 2012, respectively.

We have established an exploration and development capital budget of $355 million to $375 million for 2013 that continues our focus on higher-margin oil opportunities. Remaining 2013 quarterly capital expenditures are forecasted to be lower than the first quarter as the benefit of the drilling carry associated with the Eagle Ford Shale development agreement is realized into 2014. Primary factors impacting the level of our capital expenditures include 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.

FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” the negative of such words or other variations of such words, and similar expressions, identify forward-looking statements. Similarly, statements that describe our strategies, initiatives, objectives, plans, or goals are forward-looking. These forward-looking statements are based on our current intent, plans, beliefs, expectations, estimates, projections, forecasts, and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These statements are not guarantees of future performance.

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


•	estimates of our oil and natural gas reserves;


•	estimates of our future oil and natural gas production, including estimates of any increases or decreases in our production, and the liquids/natural gas mix of that production;


•	our future financial condition and results of operations;


•	our future revenues, cash flows, and expenses;


•	our access to capital and our anticipated liquidity;


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

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•	our outlook on oil and natural gas prices;


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


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


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


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

We believe the expectations, estimates, projections, beliefs, forecasts, and assumptions reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements 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 natural gas. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included or incorporated in Part I of our 2012 Annual Report on Form 10-K.

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.

RECONCILIATION OF NON-GAAP MEASURE

Adjusted EBITDA

In addition to reporting net earnings (loss) as defined under GAAP, we also present Adjusted EBITDA, which is a performance measure that is not calculated in accordance with GAAP. Adjusted EBITDA consists of net earnings (loss) before interest expense, income taxes, depreciation, depletion, and amortization, as well as other non-cash operating items such as unrealized gains and losses on derivative instruments, ceiling test write-downs of oil and natural gas properties, accretion of asset retirement obligations, and other items presented in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to, GAAP measurements, such as net earnings (loss) (its most comparable GAAP financial measure), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating interest, taxes, depreciation, depletion, amortization, and other items from earnings, we believe the result is a useful measure across time in evaluating our fundamental core operating performance. Management also uses Adjusted EBITDA to manage our business, including in preparing our annual operating budget and financial projections. We believe that Adjusted EBITDA is also useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) and revenues to measure operating performance. The following table provides a reconciliation of net loss, the most directly comparable GAAP measure, to Adjusted EBITDA for the periods presented.

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	Three Months Ended
	March 31,
	2013			2012
	(In Thousands)
Net loss	$	(67,948	)	$	(32,673	)
Income tax expense	337			915
Unrealized losses (gains) on derivative instruments, net	38,311			(5,312		)
Interest expense	36,128			33,392
Loss on debt extinguishment	25,223			—
Accretion of asset retirement obligations	1,244			1,598
Ceiling test write-down of natural gas properties	—			34,817
Depreciation, depletion, and amortization	48,543			66,970
Stock-based compensation	3,647			3,017
Legal proceeding/severance costs	5,821			22,847
Rig stacking	3,038			—
Adjusted EBITDA	$	94,344		$	125,571

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We produce and sell natural gas, oil, and NGLs in the United States. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. In order to reduce the impact of fluctuations in commodity prices, we make use of a commodity hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other derivative instruments with counterparties who, in general, are lenders, or affiliates of such lenders, under our Credit Facility. These instruments, which are typically based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.

Swaps

In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher than the fixed price, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of March 31, 2013, we had entered into the following swaps:



Commodity Swaps
	Natural Gas (NYMEX HH)						Oil (NYMEX WTI)
Remaining Swap Term	Bbtu per Day	Weighted Average Hedged Price per MMBtu		Fair Value (In Thousands)			Barrels per Day	Weighted Average Hedged Price per Bbl		Fair Value (In Thousands)
April 2013 - December 2013	160	$	3.98	$	(6,205	)	4,000	$	95.53	$	(1,371	)
Calendar 2014	80	4.34		3,168			—	—		—

Commodity Options

In connection with several natural gas and oil swaps entered into, we granted swaptions to the swap counterparties in exchange for our receiving premium hedged prices on the natural gas and oil swaps. These swaptions grant the swap counterparties the option to enter into future swaps with us and may not be exercised until their expiration dates. The table below sets forth the outstanding swaptions as of March 31, 2013.



Commodity Options
		Natural Gas (NYMEX HH)						Oil (NYMEX WTI)
Underlying Term	Option Expiration	Underlying Bbtu Per Day	Underlying Hedged Price per MMBtu		Fair Value (In Thousands)			Underlying Barrels Per Day	Underlying Hedged Price per Bbl		Fair Value (In Thousands)
Gas Swaptions:
Calendar 2014	December 2013	30	$	4.50	$	(2,582	)	—	$	—	$	—
Calendar 2014	December 2013	10	4.51		(854		)	—	—		—
Oil Swaptions:
Calendar 2014	December 2013	—	—		—			4,000	100.00		(3,933		)
Calendar 2014	December 2013	—	—		—			1,000	109.00		(361		)
Calendar 2015	December 2014	—	—		—			3,000	100.00		(4,110		)

The estimated fair value at March 31, 2013 of all our commodity derivative instruments based on various valuation inputs, including published forward prices, was a net liability of approximately $16 million.

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Interest Rate Risk

We have entered into interest rate derivative instruments in an attempt to manage the mix of fixed and floating interest rates within our debt portfolio. As of March 31, 2013, we had entered into the following fixed-to-floating interest rate swaps:



Interest Rate Swaps
Remaining Swap Term	Notional Amount (In Thousands)		Weighted Average Floating Rate	Weighted Average Fixed Rate		Fair Value (In Thousands)
April 2013 - February 2014	$	500,000	1 month LIBOR + 5.89%	8.50	%	$	9,910

The estimated fair value at March 31, 2013 of all our interest rate derivative instruments based on various valuation inputs, including published forward rates, was an asset of approximately $10 million.

Derivative Fair Value Reconciliation

The table below sets forth the changes that occurred in the fair values of our derivative instruments during the three months ended March 31, 2013, beginning with the fair value of our derivative instruments on December 31, 2012. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Due to the volatility of oil, natural gas, and NGL prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period. Actual gains and losses recognized related to our commodity derivative instruments will likely differ from those estimated at March 31, 2013 and will depend exclusively on the price of the commodities on the settlement dates specified by the derivative instruments.



	Fair Value of Derivative Contracts
	Commodity			Interest Rate			Total
	(In Thousands)
As of December 31, 2012	$	18,914		$	13,060		$	31,974
Net decrease in fair value	(25,513		)	(68		)	(25,581		)
Net contract gains realized	(9,649		)	(3,082		)	(12,731		)
As of March 31, 2013	$	(16,248	)	$	9,910		$	(6,338	)

Interest Rates on Borrowings

The following table presents principal amounts and related interest rates by year of maturity for our Credit Facility and senior notes at March 31, 2013.



	2013			2016			2019			2020			Total
	(Dollar Amounts in Thousands)
Credit facility:
Borrowings outstanding	$	—		$	140,000		$	—		$	—		$	140,000
Interest rate⁽¹⁾	—			1.75		%	—			—			1.75		%
Senior notes:
Principal outstanding	$	12		$	—		$	1,000,000		$	500,000		$	1,500,012
Fixed interest rate	7.00		%	—			7.25		%	7.50		%	7.33		%
Effective interest rate⁽²⁾	7.49		%	—			7.24		%	7.50		%	7.33		%

____________________________________________


(1)	Weighted average interest rate as of March 31, 2013.


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

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Foreign Currency Exchange Risk

We conduct business in Italy and South Africa, and thus are subject to foreign currency exchange rate risk on cash flows related primarily to expenses and investing transactions. We have not entered into any foreign currency forward contracts or other similar financial instruments to manage this risk. Expenditures incurred relative to the foreign concessions held by us outside of North America have been primarily United States dollar-denominated.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Forest and its consolidated subsidiaries is made known to the officers who certify Forest’s financial reports and the Board of Directors.

Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Michael N. Kennedy, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the quarterly period ended March 31, 2013 (the “Evaluation Date”). Based on this evaluation, they believe that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms; and (ii) is accumulated and communicated to Forest’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended March 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

There have been no material changes to the disclosure included in Part I, Item 3, of the Annual Report on Form 10-K for the year ended December 31, 2012.

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

Item 1A. RISK FACTORS

There have been no material changes to the risks described in Part I, Item 1A, of the Annual Report on Form 10-K for the year ended December 31, 2012.

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

Unregistered Sales of Equity Securities

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

Issuer Purchases of Equity Securities

The table below sets forth information regarding repurchases of our common stock during the first quarter of 2013. The shares repurchased represent shares of our common stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Forest does not consider this a share buyback program.



Period	Total # of Shares Purchased	Average Price Paid Per Share		Total # of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum # (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs
January 2013	31,149	$	6.89	—	—
February 2013	35,607	6.77		—	—
March 2013	6,381	5.54		—	—
First Quarter Total	73,137	$	6.71	—	—

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Item 6. EXHIBITS



(a)			Exhibits.

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

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

10.1			Acquisition and Development Agreement, dated April 11, 2013, by and between Forest Oil Corporation, STC Eagleville, LLC, Schlumberger Technology Corporation, Smith International, Inc., and M-I L.L.C., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2013.

10.2			Operating Agreement, dated April 11, 2013, by and between Forest Oil Corporation and STC Eagleville LLC, incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 17, 2013.

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

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

32.1+			Certification of Principal Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

32.2+			Certification of Principal Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

101.INS++			XBRL Instance Document.

101.SCH++			XBRL Schema Document.

101.CAL++			XBRL Calculation Linkbase Document.

101.LAB++			XBRL Label Linkbase Document.

101.PRE++			XBRL Presentation Linkbase Document.

101.DEF++			XBRL Definition Linkbase Document.

____________________________________________


*	Filed herewith.

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

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

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SIGNATURES

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



	FOREST OIL CORPORATION (Registrant)

May 7, 2013	By:	/s/ PATRICK R. MCDONALD
		Patrick R. McDonald President and Chief Executive Officer and Director (on behalf of the Registrant and as Principal Executive Officer)

	By:	/s/ MICHAEL N. KENNEDY
		Michael N. Kennedy Executive Vice President and Chief Financial Officer (on behalf of the Registrant and as Principal Financial Officer)

	By:	/s/ VICTOR A. WIND
		Victor A. Wind Senior Vice President, Chief Accounting Officer, Corporate Controller, and Treasurer (Principal Accounting Officer)

Table of Contents

Exhibit Index



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

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

10.1			Acquisition and Development Agreement, dated April 11, 2013, by and between Forest Oil Corporation, STC Eagleville, LLC, Schlumberger Technology Corporation, Smith International, Inc., and M-I L.L.C., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2013.

10.2			Operating Agreement, dated April 11, 2013, by and between Forest Oil Corporation and STC Eagleville LLC, incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 17, 2013.

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

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

32.1+			Certification of Principal Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

32.2+			Certification of Principal Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

101.INS++			XBRL Instance Document.

101.SCH++			XBRL Schema Document.

101.CAL++			XBRL Calculation Linkbase Document.

101.LAB++			XBRL Label Linkbase Document.

101.PRE++			XBRL Presentation Linkbase Document.

101.DEF++			XBRL Definition Linkbase Document.

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*	Filed herewith.

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