Edgar Filing: FOREST OIL CORP

FST-09.30.2013-10Q



	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 September 30, 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 October 30, 2013 there were 119,664,093 shares of the registrant’s common stock, par value $.10 per share, outstanding.

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FOREST OIL CORPORATION

INDEX TO FORM 10-Q

September 30, 2013



Part I—FINANCIAL INFORMATION	1
Item 1—Financial Statements	1
Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	1
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012	3
Condensed Consolidated Statement of Shareholders’ Equity for the Nine Months Ended September 30, 2013	4
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 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	28
Item 3—Quantitative and Qualitative Disclosures About Market Risk	43
Item 4—Controls and Procedures	46
Part II—OTHER INFORMATION	47
Item 1—Legal Proceedings	47
Item 1A—Risk Factors	47
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 6—Exhibits	48
Signatures	49

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands, Except Share Amounts)



	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	2,121		$	1,056
Accounts receivable	63,734			67,516
Derivative instruments	16,461			40,190
Other current assets	8,905			16,318
Total current assets	91,221			125,080
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $8,369,028 and $8,237,186	1,312,337			1,459,312
Unproved	187,870			277,798
Net oil and natural gas properties	1,500,207			1,737,110
Other property and equipment, net of accumulated depreciation and amortization of $50,412 and $46,908	13,425			17,128
Net property and equipment	1,513,632			1,754,238
Deferred income taxes	6,221			14,681
Goodwill	239,420			239,420
Derivative instruments	3,039			8,335
Other assets	55,784			60,108
	$	1,909,317		$	2,201,862
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	189,362		$	164,786
Accrued interest	23,567			23,407
Derivative instruments	5,467			9,347
Deferred income taxes	6,221			14,681
Current portion of long-term debt	—			12
Other current liabilities	14,904			14,092
Total current liabilities	239,521			226,325
Long-term debt	1,615,322			1,862,088
Asset retirement obligations	25,323			56,155
Derivative instruments	4,134			7,204
Other liabilities	88,107			92,914
Total liabilities	1,972,407			2,244,686
Shareholders’ equity:
Preferred stock, none issued and outstanding	—			—
Common stock, 119,757,396 and 118,245,320 shares issued and outstanding	11,976			11,825
Capital surplus	2,552,707			2,541,859
Accumulated deficit	(2,608,289		)	(2,575,994		)
Accumulated other comprehensive loss	(19,484		)	(20,514		)
Total shareholders’ equity (deficit)	(63,090		)	(42,824		)
	$	1,909,317		$	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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Revenues:
Oil, natural gas, and natural gas liquids sales	$	118,028		$	156,014		$	352,856		$	450,609
Interest and other	166			54			326			123
Total revenues	118,194			156,068			353,182			450,732
Costs, expenses, and other:
Lease operating expenses	19,245			27,426			59,616			82,167
Production and property taxes	4,667			8,842			11,912			26,935
Transportation and processing costs	2,790			3,580			9,168			11,167
General and administrative	9,765			13,416			42,893			45,221
Depreciation, depletion, and amortization	43,973			73,845			136,320			213,802
Ceiling test write-down of oil and natural gas properties	—			329,957			—			713,750
Impairment of properties	—			79,529			—			79,529
Interest expense	29,519			36,223			95,039			103,932
Realized and unrealized losses (gains) on derivative instruments, net	5,533			22,795			(497		)	(40,744		)
Other, net	1,075			11,727			31,488			42,102
Total costs, expenses, and other	116,567			607,340			385,939			1,277,861
Earnings (loss) before income taxes	1,627			(451,272		)	(32,757		)	(827,129		)
Income tax (benefit) expense	(587		)	7,280			(462		)	175,269
Net earnings (loss)	$	2,214		$	(458,552	)	$	(32,295	)	$	(1,002,398	)

Basic earnings (loss) per common share	$	.02		$	(3.97	)	$	(.28	)	$	(8.73	)
Diluted earnings (loss) per common share	$	.02		$	(3.97	)	$	(.28	)	$	(8.73	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In Thousands)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013			2012
Net earnings (loss)	$	2,214	$	(458,552	)	$	(32,295	)	$	(1,002,398	)
Other comprehensive income:
Defined benefit postretirement plans - amortization of actuarial losses, net of tax	343		185			1,030			558
Total other comprehensive income	343		185			1,030			558

Total comprehensive income (loss)	$	2,557	$	(458,367	)	$	(31,265	)	$	(1,001,840	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited)

(In Thousands)



	Common Stock					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	153		15			561			—			—			576
Restricted stock issued, net of forfeitures	1,598		160			(160		)	—			—			—
Amortization of stock-based compensation	—		—			11,796			—			—			11,796
Other, net	(239	)	(24		)	(1,349		)	—			—			(1,373		)
Net loss	—		—			—			(32,295		)	—			(32,295		)
Other comprehensive income	—		—			—			—			1,030			1,030
Balances at September 30, 2013	119,757		$	11,976		$	2,552,707		$	(2,608,289	)	$	(19,484	)	$	(63,090	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)



	Nine Months Ended
	September 30,
	2013			2012
Operating activities:
Net loss	$	(32,295	)	$	(1,002,398	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	136,320			213,802
Deferred income tax	—			208,990
Unrealized losses on derivative instruments, net	22,076			46,372
Ceiling test write-down of oil and natural gas properties	—			713,750
Impairment of properties	—			79,529
Stock-based compensation expense	7,276			12,227
Loss on debt extinguishment	25,223			—
Other, net	3,710			11,352
Changes in operating assets and liabilities:
Accounts receivable	2,202			9,070
Other current assets	5,896			4,426
Accounts payable and accrued liabilities	15,494			2,182
Accrued interest and other	(1,917		)	(13,477		)
Net cash provided by operating activities	183,985			285,825
Investing activities:
Capital expenditures for property and equipment:
Exploration, development, and leasehold acquisition costs	(290,923		)	(598,882		)
Other fixed assets	(1,266		)	(6,011		)
Proceeds from sales of assets	370,437			8,902
Net cash provided (used) by investing activities	78,248			(595,991		)
Financing activities:
Proceeds from bank borrowings	457,000			651,000
Repayments of bank borrowings	(407,000		)	(756,000		)
Issuance of senior notes, net of issuance costs	—			491,250
Redemption of senior notes	(321,327		)	—
Change in bank overdrafts	11,117			(37,716		)
Other, net	(958		)	(2,211		)
Net cash (used) provided by financing activities	(261,168		)	346,323
Net increase in cash and cash equivalents	1,065			36,157
Cash and cash equivalents at beginning of period	1,056			3,012
Cash and cash equivalents at end of period	$	2,121		$	39,169
Cash paid during the period for:
Interest (net of capitalized amounts)	$	89,753		$	88,619
Income taxes (net of refunded amounts)	(736		)	979
Non-cash investing activities:
Decrease in accrued capital expenditures	$	(6,290	)	$	(22,878	)
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 September 30, 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 NGLs 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 NGL 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.

Certain amounts in the prior year financial statements have been reclassified to conform to the 2013 financial statement presentation.

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

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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 and cash-settled performance units issued under Forest’s stock incentive plans do not participate in dividends. Share-settled performance units issued under Forest’s stock incentive plans do not participate in dividends in their current form. Holders of these 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. Share-settled 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 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 share-settled 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 share-settled 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 nine months ended September 30, 2013 and the three and nine months ended September 30, 2012. Unvested restricted stock grants were not included in the calculation of diluted earnings per share for the three months ended September 30, 2013 as their inclusion would have an antidilutive effect.

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In Thousands)
Net earnings (loss)	$	2,214		$	(458,552	)	$	(32,295	)	$	(1,002,398	)
Less: net earnings attributable to participating securities	(67		)	—			—			—
Net earnings (loss) for basic and diluted earnings (loss) per share	$	2,147		$	(458,552	)	$	(32,295	)	$	(1,002,398	)

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



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2013	2012	2013	2012
	(In Thousands)
Weighted average common shares outstanding during the period for basic earnings (loss) per share	116,242	115,417	115,979	114,784
Dilutive effects of potential common shares	—	—	—	—
Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings (loss) per share	116,242	115,417	115,979	114,784

(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 and nine months ended September 30, 2013 and 2012, and the remaining unamortized amounts and weighted average amortization period as of September 30, 2013.



	Restricted Stock			Performance Units			Phantom Stock Units			Total⁽¹⁾⁽²⁾
	(In Thousands)
Three Months Ended September 30, 2013:
Total stock-based compensation costs	$	1,644		$	301		$	1,762		$	3,707
Less: stock-based compensation costs capitalized	(877		)	(245		)	(828		)	(1,950		)
Stock-based compensation costs expensed	$	767		$	56		$	934		$	1,757
Nine Months Ended September 30, 2013:
Total stock-based compensation costs	$	9,089		$	3,034		$	3,537		$	15,660
Less: stock-based compensation costs capitalized	(3,871		)	(959		)	(1,715		)	(6,545		)
Stock-based compensation costs expensed	$	5,218		$	2,075		$	1,822		$	9,115
Unamortized stock-based compensation costs⁽³⁾	$	15,541		$	8,647		$	11,500		$	35,688
Weighted average amortization period remaining	1.6 years			2.1 years			1.9 years			1.8 years
Three Months Ended September 30, 2012:
Total stock-based compensation costs	$	3,500		$	1,273		$	909		$	5,682
Less: stock-based compensation costs capitalized	(1,435		)	(455		)	(402		)	(2,292		)
Stock-based compensation costs expensed	$	2,065		$	818		$	507		$	3,390
Nine Months Ended September 30, 2012:
Total stock-based compensation costs	$	12,219		$	5,630		$	796		$	18,645
Less: stock-based compensation costs capitalized	(4,630		)	(1,322		)	(532		)	(6,484		)
Stock-based compensation costs expensed	$	7,589		$	4,308		$	264		$	12,161

____________________________________________


(1)	Forest also maintains an employee stock purchase plan (which is not included in the table) under which $.04 million and $.2 million of compensation cost was recognized for the three and nine month periods ended September 30, 2013, respectively, and $.1 million and $.3 million of compensation cost was recognized for the three and nine month periods ended September 30, 2012, respectively.

(2)

In connection with the divestiture of the South Texas oil and natural gas properties in the first quarter of 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, in the first quarter of 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 nine months ended September 30, 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 for liability-based awards are based on the closing price of Forest’s common stock at the reporting period end.

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Stock Options

The following table summarizes stock option activity in the Plans for the nine months ended September 30, 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	(223,800	)	19.87
Outstanding at September 30, 2013	647,016		$	17.16	$	—	647,016

____________________________________________


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

Restricted Stock, Performance Units, and Phantom Stock Units

The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Plans for the nine months ended September 30, 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⁾	2,163,877		6.04				1,182,500		5.47				1,724,701		6.05
Vested	(837,894	)	21.67		$	4,669	(203,240	)	19.60		$	—	(93,044	)	10.55		$	627
Forfeited	(565,900	)	11.95				(256,500	)	9.59				(286,904	)	8.65
Unvested at September 30, 2013	3,481,720		$	10.38			1,661,940		$	8.61			2,506,490		$	7.37

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(1)	All of the unvested phantom stock units at September 30, 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 nine months ended September 30, 2013 were settled in cash.

(2)

Of the restricted stock shares granted during the nine months ended September 30, 2013, 1,229,901 shares vest in increments of 33.3% on each of the first three anniversary dates of the grant. All other Forest restricted stock grants cliff vest on the third anniversary of the date of grant. Additionally, during the nine months ended September 30, 2013, Forest granted 950,000 performance units that are cash-settled, with the settlement amount dependent upon Forest’s relative total shareholder return in comparison to an identified peer group over a thirty-six month performance period. These performance units have been accounted for as a liability within the Condensed Consolidated Financial Statements. All of the other outstanding performance units are share-settled and utilize the same relative total shareholder return criteria to determine the settlement amount, other than certain peers used for comparison purposes. The share-settled performance units have been accounted for as equity-based awards within the Condensed Consolidated Financial Statements.

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(4) DEBT

The components of debt are as follows:



	September 30, 2013						December 31, 2012
	Principal		Unamortized Premium		Total		Principal			Unamortized Premium (Discount)			Total
	(In Thousands)
Credit facility	$	115,000	$	—	$	115,000	$	65,000		$	—		$	65,000
7% senior subordinated notes due 2013⁽¹⁾	—		—		—		12			—			12
8½% senior notes due 2014⁽²⁾	—		—		—		300,000			(3,277		)	296,723
7¼% senior notes due 2019	1,000,000		322		1,000,322		1,000,000			365			1,000,365
7½% senior notes due 2020	500,000		—		500,000		500,000			—			500,000
Total debt	1,615,000		322		1,615,322		1,865,012			(2,912		)	1,862,100
Less: current portion of long-term debt	—		—		—		(12		)	—			(12		)
Long-term debt	$	1,615,000	$	322	$	1,615,322	$	1,865,000		$	(2,912	)	$	1,862,088

____________________________________________


(1)	In June 2013, Forest redeemed the 7% senior subordinated notes due 2013 at their maturity.


(2)	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.

Bank Credit Facility

As of September 30, 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.

On September 12, 2013, the Company entered into the First Amendment to the Credit Facility (the “First Amendment”), which was effective as of that date. The First Amendment amended, among other things, the permitted ratio of total debt to EBITDA and the definition of total debt used in the ratio calculation, and reduced the borrowing base, which governs Forest’s availability under the Credit Facility.

As of September 30, 2013, the borrowing base under the Credit Facility was $700.0 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 natural gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. In addition to the scheduled semi-annual redeterminations, Forest and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined. The borrowing base is also subject to automatic adjustments if certain events occur, such as if Forest or any of its Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that Forest or any of its Restricted Subsidiaries may issue to refinance 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 having a fair market value, including any economic loss of unwinding any related hedging agreement, in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount equal to either (i) 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 resulted in a $170.0 million reduction to the borrowing base effective February 15, 2013.

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The next scheduled semi-annual redetermination of the borrowing base will occur on or about May 1, 2014. However, Forest expects the pending sale of its Panhandle properties to result in a reduction to its borrowing base when the transaction closes, which is expected to be in late November 2013. See Note 5 for discussion of Forest’s divestiture activity. 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 natural gas properties and related assets of Forest and its U.S. subsidiaries.

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 First Amendment to the Credit Facility provides that Forest will not permit its ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended (i) for any time on or before September 11, 2013, to be greater than 4.50 to 1.00, (ii) for any time after September 11, 2013 and on or before March 31, 2014 to be greater than 5.00 to 1.00, (iii) for any time after April 1, 2014 and on or before June 30, 2014 to be greater than 4.75 to 1.00, and (iv) for any time after June 30, 2014, to be greater than 4.50 to 1.00. The First Amendment also amends the definition of total debt such that, during any period of four fiscal quarters that includes the calendar quarter in which the Panhandle divestiture closes, any cash proceeds from the Panhandle divestiture that are reported on Forest’s consolidated balance sheet on such date are subtracted from total debt. Depending on Forest’s overall level of indebtedness, this covenant may limit Forest’s ability to borrow funds as needed under the Credit Facility. Forest’s ratio of total debt to EBITDA for the four consecutive fiscal quarter period ended September 30, 2013, as calculated in accordance with the Credit Facility, was 4.52.

At September 30, 2013, there were outstanding borrowings of $115.0 million under the Credit Facility at a weighted average interest rate of 1.7%, and Forest had used the Credit Facility for $2.1 million in letters of credit.

(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 September 30, 2013 and 2012, Forest capitalized $6.6 million and $9.3 million, respectively, of general and administrative costs (including stock-based compensation). During the nine months ended September 30, 2013 and 2012, Forest capitalized $27.0 million and $29.6 million, respectively, of general and administrative costs (including stock-based compensation). During the three months ended September 30, 2013 and 2012, Forest capitalized $.9 million and $1.7 million, respectively, of interest costs attributed to unproved properties. During the nine months ended September 30, 2013 and 2012, Forest capitalized $2.0 million and $5.8 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.

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During the third quarter of 2012, Forest recorded a $66.9 million impairment of its unproved properties in South Africa based on several unsuccessful attempts to sell the properties for an amount that would allow Forest to recover the carrying amount of its investment in these properties. Because Forest had no proved reserves in South Africa, the impairment was reported as a period expense, rather than being added to the costs to be amortized, and is included in the Condensed Consolidated Statement of Operations within the “Impairment of properties” line item. In December 2012, Forest entered into agreements to sell its South African subsidiaries and to abandon a certain Exploration Right in South Africa in connection with the sale of the Exploration Right. Forest is currently awaiting approval of both sales by the government of the Republic of South Africa.

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

Forest did not incur a ceiling test write-down during the nine months ended September 30, 2013, however, ceiling test write-downs of the United States cost center may be required in future 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 September 30, 2013, unproved properties are impaired, 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 and nine months ended September 30, 2012, Forest recorded ceiling test write-downs of its United States cost center of $330.0 million and $678.9 million, respectively, primarily due to a decrease in natural gas and NGL prices used in the calculation of the present value of future net revenues. 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. A significant alteration would not ordinarily be expected to occur for sales involving less than 25% of the reserve quantities of a given 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 October 2013 Forest entered into an agreement to sell all of its oil and natural gas properties located in the Texas Panhandle Area for $1.0 billion in cash. The transaction is expected to close in November 2013, subject to

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customary closing conditions and purchase price adjustments. Forest intends to use the proceeds from the divestiture to reduce its indebtedness. These properties accounted for $51.5 million and $157.5 million of the Company’s oil, natural gas, and NGL revenues for the three and nine months ended September 30, 2013, respectively.

In August 2013, Forest entered into an agreement to sell a portion of its largely undeveloped acreage position located in Crockett County in the Permian Basin of West Texas for $35.0 million in cash. This transaction closed on September 10, 2013, and Forest received net proceeds of $31.4 million, after customary purchase price adjustments. Forest retained a Permian Basin acreage position located in Pecos and Reeves Counties, Texas. Forest used the proceeds from this divestiture to reduce outstanding borrowings under the Credit Facility.

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 Forest has received net proceeds of $320.9 million, after customary purchase price adjustments. Forest used the proceeds from this divestiture to redeem the remaining $300.0 million of its 8½% senior notes due 2014.

In August 2012, Forest entered into an agreement to sell the majority of its East Texas natural gas gathering assets for $34.0 million in cash. This transaction closed on October 31, 2012, and Forest received net proceeds of $28.8 million, after customary purchase price adjustments. At the time of closing, there were up to $9.0 million of additional performance payments that Forest could earn contingent upon future activity including the number of additional wells drilled by Forest and connected to the buyer’s gathering facilities. During the nine months ended September 30, 2013, Forest earned and received $2.5 million of these performance payments. As of September 30, 2013, there are $6.0 million of contingent performance payments that may still be earned. In conjunction with the sale, Forest entered into a ten-year natural gas gathering agreement with the buyer under which Forest pays market-based gathering rates and has committed the production from its existing and future operated wells located within five miles of the gathering system as it was configured at the time of sale. During the third quarter of 2012, these assets were written down to their estimated fair value less cost to sell, resulting in a $12.7 million impairment charge, which is included in the Condensed Consolidated Statement of Operations within the “Impairment of properties” line item.

Acquisition and Development Agreement

In April 2013, Forest entered into an Acquisition and Development Agreement (“ADA”) with a third-party for the future development of Forest’s Eagle Ford Shale acreage in Gonzales County, Texas. Under the terms of the ADA, the third-party will pay a $90.0 million drilling carry in the form of future drilling and completion services and related development capital in exchange for a 50% working interest in Forest’s Eagle Ford Shale acreage position. Upon completion of the phased contribution of the drilling carry, Forest and the third-party will participate in future drilling on a 50/50 basis. The ADA 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 Forest retained all of its interests in wells and production that were spud prior to November 28, 2012. Forest is the operator of the drilling program. As of September 30, 2013, Forest had realized $44.1 million of the drilling carry and currently expects that it will be fully realized by mid-2014.

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:



	Nine Months Ended September 30, 2013
	(In Thousands)
Asset retirement obligations at beginning of period	$	58,585
Accretion expense	2,339
Liabilities incurred	2,197
Liabilities settled	(2,169		)
Disposition of properties	(34,189		)
Revisions of estimated liabilities	1,451
Asset retirement obligations at end of period	28,214
Less: current asset retirement obligations	(2,891		)
Long-term asset retirement obligations	$	25,323

(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 (36)% and 1% for the three and nine months ended September 30, 2013, respectively, and (2)% and (21)% for the three and nine months ended September 30, 2012, respectively, were primarily due to changes in the valuation allowance on Forest’s deferred tax assets. The negative income tax rate for the three months ended September 30, 2013 is due to state income tax refunds received.

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 September 30, 2013 and December 31, 2012 are set forth in the table below.



	September 30, 2013		December 31, 2012
	Using Significant Other Observable Inputs (Level 2)⁽¹⁾
	(In Thousands)
Assets:
Derivative instruments⁽²⁾:
Commodity	$	19,500	$	35,465
Interest rate	—		13,060
Total assets	$	19,500	$	48,525
Liabilities:
Derivative instruments⁽²⁾:
Commodity	$	9,601	$	16,551
Total liabilities	$	9,601	$	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 and nine months ended September 30, 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 currently outstanding derivative assets and liabilities include commodity 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.

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



	September 30, 2013
					Fair Value Measurements
	Carrying Amount		Total Fair Value⁽¹⁾		Using Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Using Significant Other Observable Inputs (Level 2)
	(In Thousands)
Assets:
Derivative instruments	$	19,500	$	19,500	$	—	$	19,500
Liabilities:
Derivative instruments	9,601		9,601		—		9,601
Credit facility	115,000		115,000		—		115,000
7¼% senior notes due 2019	1,000,322		1,017,000		1,017,000		—
7½% senior notes due 2020	500,000		498,125		498,125		—

__________________________________________

(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.



	December 31, 2012
					Fair Value Measurements
	Carrying Amount		Total Fair Value⁽¹⁾		Using Quoted Prices in Active Markets for Identical Liabilities (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)

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(8) DERIVATIVE INSTRUMENTS

Commodity Derivatives

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

The table below sets forth Forest’s outstanding commodity swaps as of September 30, 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
October 2013	130	$	4.03	6,000	$	96.92
November 2013 - December 2013	125	4.02		6,000	96.92
Calendar 2014	80	4.34		3,500	95.34

In connection with several natural gas and oil swaps entered into, Forest granted option instruments (several swaptions and puts) to the swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas and oil swaps. Under the terms of the swaption agreements, the counterparties have the option to enter into future swaps with Forest. The swaptions may not be exercised until their expiration dates. Under the terms of the put agreements, the counterparties have the option to put specified quantities of oil to Forest at specified prices. The puts may be exercised monthly by the counterparties. The table below sets forth the outstanding options as of September 30, 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	—	—		2,000	100.00
Calendar 2015	December 2014	—	—		3,000	100.00
Calendar 2015	December 2014	—	—		1,000	106.00
Calendar 2015	December 2014	—	—		1,000	99.75
Calendar 2015	December 2014	—	—		1,000	99.00
Oil Put Options:
Monthly Calendar 2014	Monthly Calendar 2014	—	—		2,000	70.00

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Interest Rate Derivatives

Forest voluntarily terminated its interest rate swaps in June 2013 for proceeds of $11.4 million, which are included as realized gains in the line item “Realized and unrealized losses (gains) on derivative instruments, net” in the Condensed Consolidated Statement of Operations for the nine months ended September 30, 2013.

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.



	September 30, 2013		December 31, 2012
	(In Thousands)
Current assets:
Derivative instruments:
Commodity	$	16,461	$	28,690
Interest rate	—		11,500
Total current assets	$	16,461	$	40,190
Long-term assets:
Derivative instruments:
Commodity	$	3,039	$	6,775
Interest rate	—		1,560
Total long-term assets	$	3,039	$	8,335
Current liabilities:
Derivative instruments:
Commodity	$	5,467	$	9,347
Long-term liabilities:
Derivative instruments:
Commodity	$	4,134	$	7,204

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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. Realized gains and losses represent cash settlements on derivative instruments and unrealized gains and losses represent changes in fair value of derivative instruments. These derivative instruments are not designated as hedging instruments for accounting purposes.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In Thousands)
Commodity derivatives:
Realized gains	$	(1,145	)	$	(26,242	)	$	(9,688	)	$	(78,637	)
Unrealized losses	6,678			50,231			9,016			41,659
Interest rate derivatives:
Realized gains	—			(2,758		)	(12,885		)	(8,479		)
Unrealized losses	—			1,564			13,060			4,713
Realized and unrealized losses (gains) on derivative instruments, net	$	5,533		$	22,795		$	(497	)	$	(40,744	)

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

Credit Risk

Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. (“ISDA”) Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes, with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties’ requirements and the specific types of derivatives to be transacted. As of September 30, 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

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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 $14.9 million at September 30, 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 September 30, 2013, Forest owed a net derivative liability to its counterparties, the fair value of which was $5.0 million. In the absence of netting provisions, at September 30, 2013, Forest would be exposed to a risk of loss of $19.5 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $9.6 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
	September 30, 2013			December 31, 2012
	(In Thousands)
Gross amounts of recognized assets	$	19,500		$	48,525
Gross amounts offset in the balance sheet	—			—
Net amounts of assets presented in the balance sheet	19,500			48,525
Gross amounts not offset in the balance sheet:
Derivative instruments	(4,643		)	(13,537		)
Cash collateral received	—			—
Net amount	$	14,857		$	34,988



	Derivative Liabilities
	September 30, 2013			December 31, 2012
	(In Thousands)
Gross amounts of recognized liabilities	$	9,601		$	16,551
Gross amounts offset in the balance sheet	—			—
Net amounts of liabilities presented in the balance sheet	9,601			16,551
Gross amounts not offset in the balance sheet:
Derivative instruments	(4,643		)	(13,537		)
Cash collateral pledged	—			—
Net amount	$	4,958		$	3,014

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

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(9) COSTS, EXPENSES, AND OTHER

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(In Thousands)
Accretion of asset retirement obligations	$	546	$	1,719	$	2,339	$	4,914
Loss on debt extinguishment	—		—		25,223		—
Legal proceeding liabilities	—		6,404		—		29,251
Other, net	529		3,604		3,926		7,937
	$	1,075	$	11,727	$	31,488	$	42,102

Accretion of Asset Retirement Obligations

Accretion of asset retirement obligations is the expense recognized to increase the carrying amount of the liability associated with Forest’s 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 the remaining $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

Legal proceeding liabilities for the nine months ended September 30, 2012 includes $22.8 million for the previously-disclosed arbitration award against Forest in Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al. Forest is seeking to have this award 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 $23.9 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). Forest’s other comprehensive income during the three and nine months ended September 30, 2013 consists of actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost.

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The components of other comprehensive income, both before-tax and net-of-tax, for the three and nine months ended September 30, 2013 are as follows:



	Before-Tax		Tax (Expense) / Benefit		Net-of-Tax
	(In Thousands)
Three Months Ended September 30, 2013:
Defined benefit postretirement plans
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost	$	343	$	—	$	343
Other comprehensive income	$	343	$	—	$	343
Nine Months Ended September 30, 2013:
Defined benefit postretirement plans
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost	$	1,030	$	—	$	1,030
Other comprehensive income	$	1,030	$	—	$	1,030

The change in the accumulated balance of other comprehensive income (loss) during the nine months ended September 30, 2013 is as follows:



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

Amounts reclassified from accumulated other comprehensive loss	1,030
Other comprehensive income	1,030

Balance at September 30, 2013	$	(19,484	)

____________________________________


(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 September 30, 2013 and December 31, 2012, and for the three and nine months ended September 30, 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)



	September 30, 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	$	770		$	56	$	1,295		$	—		$	2,121		$	667		$	45	$	344		$	—		$	1,056
Accounts receivable	38,415			23,273		2,645			(599		)	63,734			33,979			27,969		6,393			(825		)	67,516
Other current assets	24,957			292		117			—			25,366			55,869			286		353			—			56,508
Total current assets	64,142			23,621		4,057			(599		)	91,221			90,515			28,300		7,090			(825		)	125,080
Property and equipment, at cost	8,294,495			1,460,596		177,981			—			9,933,072			8,439,898			1,416,364		182,070			—			10,038,332
Less accumulated depreciation, depletion, and amortization	7,040,529			1,203,938		174,973			—			8,419,440			6,937,606			1,173,332		173,156			—			8,284,094
Net property and equipment	1,253,966			256,658		3,008			—			1,513,632			1,502,292			243,032		8,914			—			1,754,238
Investment in subsidiaries	104,137			—		—			(104,137		)	—			68,048			—		—			(68,048		)	—
Goodwill	216,460			22,960		—			—			239,420			216,460			22,960		—			—			239,420
Due from subsidiaries	85,994			111,080		—			(197,074		)	—			116,602			83,983		—			(200,585		)	—
Deferred income taxes	102,555			—		36,106			(132,440		)	6,221			111,015			—		36,106			(132,440		)	14,681
Other assets	58,823			—		—			—			58,823			68,443			—		—			—			68,443
	$	1,886,077		$	414,319	$	43,171		$	(434,250	)	$	1,909,317		$	2,173,375		$	378,275	$	52,110		$	(401,898	)	$	2,201,862
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	182,633		$	1,305	$	6,023		$	(599	)	$	189,362		$	157,404		$	2,133	$	6,074		$	(825	)	$	164,786
Other current liabilities	44,694			—		5,465			—			50,159			55,187			67		6,285			—			61,539
Total current liabilities	227,327			1,305		11,488			(599		)	239,521			212,591			2,200		12,359			(825		)	226,325
Long-term debt	1,615,322			—		—			—			1,615,322			1,862,088			—		—			—			1,862,088
Due to parent and subsidiaries	—			—		197,074			(197,074		)	—			—			—		200,585			(200,585		)	—
Deferred income taxes	—			132,440		—			(132,440		)	—			—			132,440		—			(132,440		)	—
Other liabilities	106,518			3,682		7,364			—			117,564			141,520			3,642		11,111			—			156,273
Total liabilities	1,949,167			137,427		215,926			(330,113		)	1,972,407			2,216,199			138,282		224,055			(333,850		)	2,244,686
Shareholders’ equity (deficit)	(63,090		)	276,892		(172,755		)	(104,137		)	(63,090		)	(42,824		)	239,993		(171,945		)	(68,048		)	(42,824		)
	$	1,886,077		$	414,319	$	43,171		$	(434,250	)	$	1,909,317		$	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 September 30,
	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	$	89,584		$	28,444		$	—		$	—		$	118,028		$	119,588		$	36,002		$	424		$	—		$	156,014
Interest and other	239			733			—			(806		)	166			1,694			1,278			—			(2,918		)	54
Equity earnings in subsidiaries	12,871			—			—			(12,871		)	—			(73,712		)	—			—			73,712			—
Total revenues	102,694			29,177			—			(13,677		)	118,194			47,570			37,280			424			70,794			156,068
Costs, expenses, and other:
Lease operating expenses	16,244			3,001			—			—			19,245			23,115			4,195			116			—			27,426
Other production expenses	7,633			(176		)	—			—			7,457			12,546			(165		)	41			—			12,422
General and administrative	9,193			615			(43		)	—			9,765			12,341			689			386			—			13,416
Depreciation, depletion, and amortization	33,218			10,197			558			—			43,973			55,978			17,433			434			—			73,845
Ceiling test write-down of oil and natural gas properties	—			—			—			—			—			324,155			—			5,802			—			329,957
Impairment of properties	—			—			—			—			—			—			—			79,529			—			79,529
Interest expense	29,520			(7		)	812			(806		)	29,519			36,224			706			2,211			(2,918		)	36,223
Realized and unrealized losses on derivative instruments, net	4,477			1,048			8			—			5,533			17,883			4,848			64			—			22,795
Other, net	1,044			100			(69		)	—			1,075			8,692			96			2,939			—			11,727
Total costs, expenses, and other	101,329			14,778			1,266			(806		)	116,567			490,934			27,802			91,522			(2,918		)	607,340
Earnings (loss) before income taxes	1,365			14,399			(1,266		)	(12,871		)	1,627			(443,364		)	9,478			(91,098		)	73,712			(451,272		)
Income tax (benefit) expense	(849		)	319			(57		)	—			(587		)	15,188			(842		)	(7,066		)	—			7,280
Net earnings (loss)	$	2,214		$	14,080		$	(1,209	)	$	(12,871	)	$	2,214		$	(458,552	)	$	10,320		$	(84,032	)	$	73,712		$	(458,552	)
Comprehensive income (loss)	$	2,557		$	14,080		$	(1,209	)	$	(12,871	)	$	2,557		$	(458,367	)	$	10,320		$	(84,032	)	$	73,712		$	(458,367	)

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (Continued)

(Unaudited)

(In Thousands)



	Nine Months Ended September 30,
	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	$	274,245		$	78,209		$	402		$	—		$	352,856		$	326,209		$	123,093		$	1,307		$	—		$	450,609
Interest and other	595			1,568			1			(1,838		)	326			3,381			1,850			—			(5,108		)	123
Equity earnings in subsidiaries	31,179			—			—			(31,179		)	—			(81,311		)	—			—			81,311			—
Total revenues	306,019			79,777			403			(33,017		)	353,182			248,279			124,943			1,307			76,203			450,732
Costs, expenses, and other:
Lease operating expenses	50,026			9,502			88			—			59,616			69,087			12,774			306			—			82,167
Other production expenses	21,027			15			38			—			21,080			36,937			1,026			139			—			38,102
General and administrative	40,886			1,509			498			—			42,893			42,300			2,040			881			—			45,221
Depreciation, depletion, and amortization	103,896			30,605			1,819			—			136,320			157,381			55,116			1,305			—			213,802
Ceiling test write-down of oil and natural gas properties	—			—			—			—			—			673,131			—			40,619			—			713,750
Impairment of properties	—			—			—			—			—			—			—			79,529			—			79,529
Interest expense	95,039			61			1,777			(1,838		)	95,039			103,932			894			4,214			(5,108		)	103,932
Realized and unrealized gains on derivative instruments, net	(392		)	(104		)	(1		)	—			(497		)	(33,044		)	(7,603		)	(97		)	—			(40,744		)
Other, net	28,719			312			2,457			—			31,488			35,259			293			6,550			—			42,102
Total costs, expenses, and other	339,201			41,900			6,676			(1,838		)	385,939			1,084,983			64,540			133,446			(5,108		)	1,277,861
Earnings (loss) before income taxes	(33,182		)	37,877			(6,273		)	(31,179		)	(32,757		)	(836,704		)	60,403			(132,139		)	81,311			(827,129		)
Income tax (benefit) expense	(887		)	526			(101		)	—			(462		)	165,694			19,075			(9,500		)	—			175,269
Net earnings (loss)	$	(32,295	)	$	37,351		$	(6,172	)	$	(31,179	)	$	(32,295	)	$	(1,002,398	)	$	41,328		$	(122,639	)	$	81,311		$	(1,002,398	)
Comprehensive income (loss)	$	(31,265	)	$	37,351		$	(6,172	)	$	(31,179	)	$	(31,265	)	$	(1,001,840	)	$	41,328		$	(122,639	)	$	81,311		$	(1,001,840	)

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)



	Nine Months Ended September 30,
	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)	$	(63,474	)	$	37,351		$	(6,172	)	$	(32,295	)	$	(921,087	)	$	41,328		$	(122,639	)	$	(1,002,398	)
Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	103,896			30,605			1,819			136,320			157,381			55,116			1,305			213,802
Deferred income tax	—			—			—			—			199,415			19,075			(9,500		)	208,990
Unrealized losses on derivative instruments, net	20,660			1,404			12			22,076			37,698			8,565			109			46,372
Ceiling test write-down of oil and natural gas properties	—			—			—			—			673,131			—			40,619			713,750
Impairment of properties	—			—			—			—			—			—			79,529			79,529
Loss on debt extinguishment	25,223			—			—			25,223			—			—			—			—
Other, net	13,918			303			(3,235		)	10,986			25,311			294			(2,026		)	23,579
Changes in operating assets and liabilities:
Accounts receivable	(6,016		)	4,696			3,522			2,202			4,657			7,164			(2,751		)	9,070
Other current assets	5,666			(6		)	236			5,896			4,463			(6		)	(31		)	4,426
Accounts payable and accrued liabilities	15,179			(248		)	563			15,494			1,915			(1,330		)	1,597			2,182
Accrued interest and other	(1,459		)	(220		)	(238		)	(1,917		)	(13,102		)	143			(518		)	(13,477		)
Net cash provided (used) by operating activities	113,593			73,885			(3,493		)	183,985			169,782			130,349			(14,306		)	285,825
Investing activities:
Capital expenditures for property and equipment	(246,651		)	(44,437		)	(1,101		)	(292,189		)	(496,178		)	(99,814		)	(8,901		)	(604,893		)
Proceeds from sales of assets	370,437			—			—			370,437			8,902			—			—			8,902
Net cash provided (used) by investing activities	123,786			(44,437		)	(1,101		)	78,248			(487,276		)	(99,814		)	(8,901		)	(595,991		)
Financing activities:
Proceeds from bank borrowings	457,000			—			—			457,000			651,000			—			—			651,000
Repayments of bank borrowings	(407,000		)	—			—			(407,000		)	(756,000		)	—			—			(756,000		)
Issuance of senior notes, net of issuance costs	—			—			—			—			491,250			—			—			491,250
Redemption of senior notes	(321,327		)	—			—			(321,327		)	—			—			—			—
Change in bank overdrafts	11,826			(484		)	(225		)	11,117			(37,661		)	(213		)	158			(37,716		)
Net activity in investments in subsidiaries	23,183			(28,953		)	5,770			—			8,480			(30,323		)	21,843			—
Other, net	(958		)	—			—			(958		)	(2,211		)	—			—			(2,211		)
Net cash (used) provided by financing activities	(237,276		)	(29,437		)	5,545			(261,168		)	354,858			(30,536		)	22,001			346,323
Net increase (decrease) in cash and cash equivalents	103			11			951			1,065			37,364			(1		)	(1,206		)	36,157
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	$	770		$	56		$	1,295		$	2,121		$	39,098		$	—		$	71		$	39,169

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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. Following the pending sale of our Texas Panhandle assets, as discussed below under “Recent Events,” our primary operational areas will be in the Eagle Ford Shale in South Texas and the East Texas / North Louisiana Area.

Recent Events

In October 2013, we entered into an agreement to sell all of our oil and natural gas properties located in the Texas Panhandle Area for $1 billion in cash. The transaction is expected to close in November 2013, subject to customary closing conditions and purchase price adjustments. We intend to use the proceeds from the divestiture to reduce debt. The equivalent sales volumes associated with these properties for the three and nine months ended September 30, 2013 were 8.7 Bcfe and 26.9 Bcfe, respectively.

In August 2013, we entered into an agreement to sell a portion of our largely undeveloped acreage position located in Crockett County in the Permian Basin of West Texas for $35 million in cash. This transaction closed in September 2013, and we received net proceeds of $31 million, after customary purchase price adjustments. We retained a Permian Basin acreage position located in Pecos and Reeves Counties, Texas. We used the proceeds from this divestiture to reduce outstanding borrowings under our bank credit facility.

In April 2013, we entered into an agreement with a third-party for the future development of our Eagle Ford Shale acreage in Gonzales County, Texas. Under the terms of the agreement, the third-party 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 the third-party 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 2013, and we retained all of our interests in wells and production that were spud prior to November 28, 2012. We are the operator of the drilling program. As of September 30, 2013, we had realized $44 million of the drilling carry and currently expect that it will be fully realized by mid-2014.

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 in February 2013, and we have received net proceeds of $321 million, after customary purchase price adjustments. 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 in November 2012, and we have received net proceeds of

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$211 million, after customary purchase price adjustments. We used the proceeds from these property sales to reduce our debt. These property sales affect the comparability of the results of our operations between the three and nine months ended September 30, 2013 and the three and nine months ended September 30, 2012 presented herein.

RESULTS OF OPERATIONS

For the three and nine months ended September 30, 2013, we recognized net earnings of $2 million and a net loss of $32 million, respectively, compared to a net loss of $459 million and $1 billion for the three and nine months ended September 30, 2012, respectively. The net loss for the nine months ended September 30, 2013 included a $25 million loss on the early termination of debt and $7 million in severance-related expenses associated with the sale of our South Texas oil and natural gas properties in the first quarter of 2013. The net losses in 2012 were primarily due to (i) non-cash ceiling test write-downs of $330 million and $714 million incurred during the three and nine months ended September 30, 2012, respectively, (ii) an $80 million impairment of properties charge recognized during the three months ended September 30, 2012, and (iii) valuation allowances placed against our deferred tax assets in each period in 2012. See “Ceiling Test Write-Down of Oil and Natural Gas Properties” below for more information regarding our ceiling test write-downs.

Adjusted EBITDA, which excludes the effects of unrealized gains and losses on derivative instruments, ceiling test write-downs, and other items, was $85 million and $268 million for the three and nine months ended September 30, 2013, respectively, as compared to $134 million and $381 million for the three and nine months ended September 30, 2012, respectively. The $49 million and $114 million decreases from the corresponding three and nine month periods, respectively, were primarily due to the sale of producing oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively, and a decrease in realized gains on derivative instruments. 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 earnings (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 and year-to-date results follows.

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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 and nine months ended September 30, 2013 and 2012 are set forth in the table below.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Sales volumes:
Oil (MBbls)	621		820		1,781		2,345
Natural gas (MMcf)	11,568		20,694		37,306		62,459
NGLs (MBbls)	655		930		2,047		2,646
Totals (MMcfe)	19,224		31,194		60,274		92,405
Revenues (in thousands):
Oil	$	63,926	$	77,359	$	174,204	$	229,101
Natural gas	34,966		51,241		118,785		137,962
NGLs	19,136		27,414		59,867		83,546
Totals	$	118,028	$	156,014	$	352,856	$	450,609
Average sales price per unit:
Oil ($/Bbl)	$	102.94	$	94.34	$	97.81	$	97.70
Natural gas ($/Mcf)	3.02		2.48		3.18		2.21
NGLs ($/Bbl)	29.22		29.48		29.25		31.57
Totals ($/Mcfe)	$	6.14	$	5.00	$	5.85	$	4.88

Our equivalent sales volumes for the three and nine months ended September 30, 2013 were 19.2 Bcfe and 60.3 Bcfe, respectively, compared to 31.2 Bcfe and 92.4 Bcfe for the three and nine months ended September 30, 2012, respectively. The decreases in equivalent sales volumes in the 2013 periods as compared to the 2012 periods were primarily due to divestitures of producing oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively, offset by an increase in oil production primarily from our Eagle Ford shale operations in South Texas.

Revenues from oil, natural gas, and NGLs were $118 million in the third quarter of 2013 compared to $156 million in the third quarter of 2012. The $38 million decrease was primarily a result of the net decrease in equivalent sales volumes discussed above. The decrease due to the net decline in equivalent sales volumes was partially offset by a 23% increase in the average sales price per Mcfe between the two periods from $5.00 per Mcfe in the third quarter of 2012 to $6.14 per Mcfe in the third quarter of 2013.

Revenues from oil, natural gas, and NGLs were $353 million in the first nine months of 2013 compared to $451 million in the first nine months of 2012. The $98 million decrease was primarily a result of the net decrease in equivalent sales volumes, which was partially offset by a 20% increase in the average sales price per Mcfe between the two periods from $4.88 per Mcfe in the first nine months of 2012 to $5.85 per Mcfe in the first nine months of 2013.

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

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Production Expense

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(In Thousands, Except Per Mcfe Data)
Production expense:
Lease operating expenses	$	19,245	$	27,426	$	59,616	$	82,167
Production and property taxes	4,667		8,842		11,912		26,935
Transportation and processing costs	2,790		3,580		9,168		11,167
Production expense	$	26,702	$	39,848	$	80,696	$	120,269
Production expense per Mcfe:
Lease operating expenses	$	1.00	$	.88	$	.99	$	.89
Production and property taxes	.24		.28		.20		.29
Transportation and processing costs	.15		.11		.15		.12
Production expense per Mcfe	$	1.39	$	1.28	$	1.34	$	1.30

Lease Operating Expenses

Lease operating expenses in the third quarter of 2013 were $19 million, or $1.00 per Mcfe, compared to $27 million, or $.88 per Mcfe, in the third quarter of 2012. Lease operating expenses in the first nine months of 2013 were $60 million, or $.99 per Mcfe, compared to $82 million, or $.89 per Mcfe, in the first nine months of 2012. Lease operating expenses decreased $8 million and $23 million in the three and nine month periods ended September 30, 2013, respectively, compared to the corresponding periods in 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 4.0% and 5.7% of oil, natural gas, and NGL revenues for the three-month periods ended September 30, 2013 and 2012, respectively, and 3.4% and 6.0% of oil, natural gas, and NGL revenues for the nine-month periods ended September 30, 2013 and 2012, respectively. The decreases in production and property taxes as a percentage of revenues in the three and nine month periods ended September 30, 2013 were 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 third quarter of 2013 were $3 million, or $.15 per Mcfe, compared to $4 million, or $.11 per Mcfe, in the third quarter of 2012. Transportation and processing costs in the first nine months of 2013 were $9 million, or $.15 per Mcfe, compared to $11 million, or $.12 per Mcfe, in the first nine months of 2012.

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General and Administrative Expense

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In Thousands)
Stock-based compensation costs	$	3,734		$	5,766		$	15,839		$	19,140
Stock-based compensation costs capitalized	(1,950		)	(2,292		)	(6,545		)	(6,509		)
	1,784			3,474			9,294			12,631

Other general and administrative costs	12,657			16,949			54,076			55,696
Other general and administrative costs capitalized	(4,676		)	(7,007		)	(20,477		)	(23,106		)
	7,981			9,942			33,599			32,590

General and administrative expense	$	9,765		$	13,416		$	42,893		$	45,221

General and administrative expense was $10 million in the third quarter of 2013, compared to $13 million in the third quarter of 2012, and was $43 million in the first nine months of 2013, compared to $45 million in the first nine months of 2012. For the first nine months of 2013, other general and administrative costs include $8 million ($6 million net of capitalized amounts) in severance costs, and stock-based compensation costs include $2 million ($1 million net of capitalized amounts) in accelerated stock-based compensation costs, both of which are related to the divestiture of the South Texas oil and natural gas properties during the first quarter of 2013 and the resulting reduction in employee headcount. For the first nine months of 2012, stock-based compensation costs include $5 million ($4 million net of capitalized amounts) in accelerated stock-based compensation costs, and other general and administrative costs include $2 million ($2 million net of capitalized amounts) in severance costs, both of which are related to the termination of our former chief executive officer. The percentage of general and administrative costs capitalized under the full cost method of accounting ranged from 39% to 41% in the periods presented.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization expense (“DD&A”) in the third quarter of 2013 was $44 million, or $2.29 per Mcfe, compared to $74 million, or $2.37 per Mcfe, in the third quarter of 2012. For the first nine months of 2013, DD&A was $136 million, or $2.26 per Mcfe, compared to $214 million, or $2.31 per Mcfe, in the first nine months of 2012.

Ceiling Test Write-Down of Oil and Natural Gas Properties

In the second and third quarters of 2012, we recorded ceiling test write-downs of our United States cost center of $349 million and $330 million, respectively, pursuant to the ceiling test limitation prescribed by the SEC for companies using the full cost method of accounting. These ceiling test write-downs were primarily a result of the decline in the twelve-month arithmetic average prices of natural gas and NGLs that were used to calculate the present value of future net revenues from our estimated proved oil and natural gas reserves prices at the end of those quarters. We have not had any ceiling test write-downs during the nine months ended September 30, 2013. However, additional write-downs of the United States cost center may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month natural gas, oil, and NGL prices used in the calculation of the present value of future net revenue from estimated production of proved oil and gas reserves declines compared to prices used as of September 30, 2013, unproved properties are impaired, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center.

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In April 2012, an Italian regional regulatory body 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 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.

Impairment of Properties

During the third quarter of 2012, we recorded a $67 million impairment of our unproved properties in South Africa based on several unsuccessful attempts to sell the properties for an amount that would allow us to recover the carrying amount of our investment in these properties. Because we had no proved reserves in South Africa, the impairment was reported as a period expense, rather than being added to the costs to be amortized, and is included in the Condensed Consolidated Statement of Operations within the “Impairment of properties” line item. In December 2012, we entered into agreements to sell our South African subsidiaries and to abandon a certain Exploration Right in South Africa in connection with the sale of the Exploration Right. We are currently awaiting approval of both sales by the government of the Republic of South Africa.

During the third quarter of 2012, we entered into an agreement to sell the majority of our East Texas natural gas gathering assets for $34 million in cash and the transaction closed in the fourth quarter of 2012. During the third quarter of 2012, these assets were written down to their estimated fair value less cost to sell, with a $13 million impairment charge included in the Condensed Consolidated Statement of Operations within the “Impairment of properties” line item.

Interest Expense

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In Thousands)
Interest costs	$	30,372		$	37,913		$	97,006		$	109,719
Interest costs capitalized	(853		)	(1,690		)	(1,967		)	(5,787		)
Interest expense	$	29,519		$	36,223		$	95,039		$	103,932

Interest expense was $30 million and $36 million for the three months ended September 30, 2013 and 2012, respectively. Interest expense was $95 million and $104 million for the nine months ended September 30, 2013 and 2012, respectively. The decreases of $7 million and $9 million in the comparable three and nine month periods, respectively, were primarily attributable to the redemption of $300 million of 8½% senior notes in October 2012, the redemption of the remaining $300 million of 8½% senior notes in March 2013, and decreased borrowings outstanding under our credit facility during 2013, partially offset by interest costs on the $500 million of 7½% senior notes issued in September 2012 and lower capitalized interest in 2013. Interest costs capitalized relate to our investments in significant unproved acreage positions that are under development. See “Liquidity and Capital Resources—Bank Credit Facility” below for more information regarding our credit facility.

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Realized and Unrealized Gains and Losses on Derivative Instruments

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In Thousands)
Realized losses (gains) on derivative instruments, net:
Oil	$	4,914		$	(2,097	)	$	4,013		$	(2,112	)
Natural gas	(6,059		)	(22,664		)	(13,701		)	(75,172		)
NGLs	—			(1,481		)	—			(1,353		)
Interest⁽¹⁾	—			(2,758		)	(12,885		)	(8,479		)
Subtotal realized gains on derivative instruments, net	(1,145		)	(29,000		)	(22,573		)	(87,116		)
Unrealized losses (gains) on derivative instruments, net:
Oil	4,721			8,390			(1,323		)	(1,129		)
Natural gas	1,957			39,087			10,339			49,554
NGLs	—			2,754			—			(6,766		)
Interest	—			1,564			13,060			4,713
Subtotal unrealized losses on derivative instruments, net	6,678			51,795			22,076			46,372
Realized and unrealized losses (gains) on derivative instruments, net	$	5,533		$	22,795		$	(497	)	$	(40,744	)

____________________________________________

(1)

In June 2013, we voluntarily terminated our fixed-to-floating interest rate swaps under which we had swapped $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%. As part of this termination, we received proceeds of $11 million, which are included as realized gains in the line item “Realized and unrealized losses (gains) on derivative instruments, net” in the Condensed Consolidated Statement of Operations for the nine months ended September 30, 2013.

Other, Net

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(In Thousands)
Accretion of asset retirement obligations	$	546	$	1,719	$	2,339	$	4,914
Loss on debt extinguishment	—		—		25,223		—
Legal proceeding liabilities	—		6,404		—		29,251
Other, net	529		3,604		3,926		7,937
	$	1,075	$	11,727	$	31,488	$	42,102

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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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In Thousands, Except Percentages)
Current income tax	$	(587	)	$	(33,830	)	$	(462	)	$	(33,721	)
Deferred income tax	—			41,110			—			208,990
Total income tax (benefit) expense	$	(587	)	$	7,280		$	(462	)	$	175,269
Effective income tax rate	(36		)%	(2		)%	1		%	(21		)%

Our effective income tax rates were (36)% and 1% for the three and nine months ended September 30, 2013, respectively, and (2)% and (21)% for the three and nine months ended September 30, 2012, respectively. The significant differences between our blended federal and state statutory income tax rate of 36% and our effective income tax rates were primarily due to changes in valuation allowances placed against our deferred tax assets. The current income tax benefit for the three and nine months ended September 30, 2013 is due to state income tax refunds received. 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 (see “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 NGLs directly impact our level of cash flow generated from operations. 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 October 31, 2013, we had hedged, via commodity swaps, approximately 64 Bcfe of our total projected 2013 production and approximately 37 Bcfe of our total projected 2014 production, excluding the volumes underlying outstanding unexercised commodity swaptions and oil put options. This level of hedging will provide a measure of certainty with respect to the cash flow that we will receive for a portion of our future production. However, these hedging activities may result in reduced income or even financial losses to us. In the future, we may determine to increase or decrease our hedging positions. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” below for more information on our derivative instruments.

As noted above, the other primary source of liquidity is our credit facility, which currently has a borrowing base of $700 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 to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended to be greater than 5.00 to 1.00 as of September 30, 2013. Future periods have differing limitations as discussed below under “Bank Credit Facility.” 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 to EBITDA for the four consecutive fiscal

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quarter period ended September 30, 2013, as calculated in accordance with the credit facility, was 4.52. We had $115 million and $136 million of borrowings outstanding under the credit facility as of September 30, 2013 and October 31, 2013, respectively. The covenant described above would currently prevent us from borrowing the full amount of our remaining borrowing base. 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 more attractive capital projects 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 $211 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 $321 million, which we used in March 2013 to redeem the remaining $300 million in principal amount of 8½% senior notes due 2014. In addition, as discussed in “Overview—Recent Events,” we have entered into an agreement with a third-party pursuant to which the third-party is funding a portion of the drilling and other development costs relating to certain Eagle Ford Shale acreage, and we have entered into an agreement to sell all of our oil and natural gas properties located in the Texas Panhandle Area for $1 billion in cash. The transaction is expected to close in November 2013, subject to customary closing conditions and purchase price adjustments. We intend to use the proceeds from the divestiture to reduce debt.

We believe that our cash flows provided by operating activities and funds available under the credit facility will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures, and our contractual 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. On September 12, 2013, we entered into the First Amendment to the Credit Facility (the “First Amendment”), which was effective as of that date. The First Amendment amended, among other things, the permitted ratio of total debt to EBITDA and the definition of total debt used in the ratio calculation, and reduced the borrowing base, which governs our availability under the Credit Facility.

As of September 30, 2013, the borrowing base under the Credit Facility was $700 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 natural gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. A reduction 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, reducing it to $700 million effective September 12, 2013. The next scheduled semi-annual redetermination of the borrowing base will occur on or about May 1, 2014. However, we expect the pending sale of our Panhandle properties to result in a reduction to the borrowing base when the transaction closes, which is expected to be in late November 2013. See Note 5 to the Condensed Consolidated Financial Statements for more information regarding our divestiture activity. In addition to the scheduled semi-annual redeterminations, we and the

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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 having a fair market value, including any economic loss of unwinding any related hedging agreement, 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.

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 natural 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 First Amendment to the Credit Facility provides that we will not permit the ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended (i) for any time on or before September 11, 2013, to be greater than 4.50 to 1.00, (ii) for any time after September 11, 2013 and on or before March 31, 2014 to be greater than 5.00 to 1.00, (iii) for any time after April 1, 2014 and on or before June 30, 2014 to be greater than 4.75 to 1.00, and (iv) for any time after June 30, 2014, to be greater than 4.50 to 1.00. The First Amendment also amends the definition of total debt such that, during any period of four fiscal quarters that includes the calendar quarter in which the Panhandle divestiture closes, any cash proceeds from the Panhandle divestiture that are reported on our consolidated balance sheet on such date are subtracted from total debt. Depending on our overall level of indebtedness, this covenant may limit our ability to borrow funds as needed under the Credit Facility. Our ratio of total debt to EBITDA for the four consecutive fiscal quarter period ended September 30, 2013, as calculated in accordance with the Credit Facility, was 4.52.

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

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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 September 30, 2013, there were outstanding borrowings of $115 million under the Credit Facility at a weighted average interest rate of 1.7%, and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $583 million. At October 31, 2013, there were outstanding borrowings of $136 million under the Credit Facility at a weighted average interest rate of 1.7%, and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $562 million. However, based on the ratio of total debt to EBITDA discussed above, our utilization of the Credit Facility is currently limited to approximately $288 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, directly purchase our production, serve as counterparties to our commodity and interest rate derivative agreements, or from time to time act as investment banking advisers with respect to our asset acquisitions and divestitures. As of October 31, 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.

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 nine months ended September 30, 2013 and 2012 were as follows:



	Nine Months Ended
	September 30,
	2013			2012
	(In Thousands)
Net cash provided by operating activities	$	183,985		$	285,825
Net cash provided (used) by investing activities	78,248			(595,991		)
Net cash (used) provided by financing activities	(261,168		)	346,323

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 nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, was primarily due to (i) decreased revenues in 2013 as compared to 2012, which was caused primarily by lower sales volumes attributable to divestitures of oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively, and (ii) lower realized gains on derivative instruments in 2013 as compared to 2012. These decreases were partially offset by (i) lower production expense in 2013 as compared to 2012, which is attributable to the oil and natural gas properties divestitures, and (ii) a decreased investment in working capital in 2013 as compared to 2012.

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The components of net cash provided (used) by investing activities for the nine months ended September 30, 2013 and 2012 were as follows:



	Nine Months Ended
	September 30,
	2013			2012
	(In Thousands)
Exploration, development, and leasehold acquisition costs⁽¹⁾	$	(290,923	)	$	(598,882	)
Proceeds from sale of assets	370,437			8,902
Other fixed asset costs	(1,266		)	(6,011		)
Net cash provided (used) by investing activities	$	78,248		$	(595,991	)

____________________________________________

(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 divestitures of oil and natural gas properties and other capital assets. The increase in net cash provided by investing activities in the nine months ended September 30, 2013 compared to the corresponding period of 2012 was primarily due to an increase in proceeds from the sale of assets, consisting principally of the South Texas divestiture in February 2013 for $321 million and the Permian Basin divestiture in September 2013 for $31 million, as well as a decrease in exploration, development, and leasehold acquisition cost expenditures during the nine months ended September 30, 2013.

Net cash used by financing activities of $261 million during the nine months ended September 30, 2013 consisted primarily of $321 million used for the redemption of the 8½% senior notes due 2014, offset partially by net proceeds from bank borrowings of $50 million. Net cash provided by financing activities of $346 million during the nine months ended September 30, 2012 consisted primarily of net proceeds of $491 million from the issuance of the 7½% senior notes due 2020, partially offset by net repayments of bank borrowings of $105 million.

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Capital Expenditures

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



	Nine Months Ended
	September 30,
	2013		2012
	(In Thousands)
Exploration, development, and acquisition costs:
Direct costs:
Exploration and development	$	257,040	$	526,936
Leasehold acquisitions	5,184		60,769
Overhead capitalized	27,022		29,615
Interest capitalized	1,967		5,787
Total capital expenditures⁽¹⁾	$	291,213	$	623,107

____________________________________________

(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 $4 million and $5 million recorded during the nine months ended September 30, 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. As the benefit of the drilling carry associated with the Eagle Ford Shale development agreement is realized into 2014, our expected capital expenditures are forecasted to be at lower levels than would otherwise be the case absent the drilling carry. See Note 5 to the Condensed Consolidated Financial Statements for more information on the drilling carry. 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;

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•	our future financial condition, results of operations, liquidity, and compliance with debt covenants;


•	our future revenues, cash flows, and expenses;


•	our access to capital and our anticipated liquidity;


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


•	our outlook on oil and natural gas prices;


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


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


•	potential future asset dispositions and other transactions, the timing of closing of such transactions and the use of proceeds, if any, from such transactions;


•	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.

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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 earnings (loss), the most directly comparable GAAP measure, to Adjusted EBITDA for the periods presented.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In Thousands)
Net earnings (loss)	$	2,214		$	(458,552	)	$	(32,295	)	$	(1,002,398	)
Income tax (benefit) expense	(587		)	7,280			(462		)	175,269
Unrealized losses on derivative instruments, net	6,678			51,795			22,076			46,372
Interest expense	29,519			36,223			95,039			103,932
Loss on debt extinguishment	—			—			25,223			—
Accretion of asset retirement obligations	546			1,719			2,339			4,914
Ceiling test write-down of oil and natural gas properties	—			329,957			—			713,750
Impairment of properties	—			79,529			—			79,529
Depreciation, depletion, and amortization	43,973			73,845			136,320			213,802
Stock-based compensation	797			2,970			7,276			12,227
Legal proceeding/severance costs	—			6,404			5,821			31,102
Rig stacking	2,076			2,744			6,372			2,744
Adjusted EBITDA	$	85,216		$	133,914		$	267,709		$	381,243

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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 September 30, 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)
October 2013	130	$	4.03	$	2,160	6,000	$	96.92	$	(982	)
November 2013 - December 2013	125	4.02		2,826		6,000	96.92		(1,580		)
Calendar 2014	80	4.34		14,042		3,500	95.34		(5		)

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Commodity Options

In connection with several natural gas and oil swaps entered into, we granted option instruments (several swaptions and puts) to the swap counterparties in exchange for our receiving premium hedged prices on the natural gas and oil swaps. Under the terms of the swaption agreements, the counterparties have the option to enter into future swaps with us. The swaptions may not be exercised until their expiration dates. Under the terms of the put agreements, the counterparties have the option to put specified quantities of oil to us at specified prices. The puts may be exercised monthly by the counterparties. The table below sets forth the outstanding options as of September 30, 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	$	(278	)	—	$	—	$	—
Calendar 2014	December 2013	10	4.51		(91		)	—	—		—
Oil Swaptions:
Calendar 2014	December 2013	—	—		—			2,000	100.00		(1,149		)
Calendar 2015	December 2014	—	—		—			3,000	100.00		(2,373		)
Calendar 2015	December 2014	—	—		—			1,000	106.00		(439		)
Calendar 2015	December 2014	—	—		—			1,000	99.75		(807		)
Calendar 2015	December 2014	—	—		—			1,000	99.00		(877		)
Oil Put Options:
Monthly Calendar 2014	Monthly Calendar 2014	—	—		—			2,000	70.00		(548		)

The estimated fair value at September 30, 2013 of all our commodity derivative instruments based on various valuation inputs, including published forward prices, was a net asset of approximately $10 million.

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Interest Rate Risk

The following table presents principal amounts and related interest rates by year of maturity for our Credit Facility and senior notes at September 30, 2013.



	2016			2019			2020			Total

Credit facility:
Borrowings outstanding (in thousands)	$	115,000		$	—		$	—		$	115,000
Interest rate⁽¹⁾	1.69		%	—			—			1.69		%
Senior notes:
Principal outstanding (in thousands)	$	—		$	1,000,000		$	500,000		$	1,500,000
Fixed interest rate	—			7.25		%	7.50		%	7.33		%
Effective interest rate⁽²⁾	—			7.24		%	7.50		%	7.33		%

____________________________________________


(1)	Weighted average variable interest rate as of September 30, 2013.


(2)	The effective interest rate on the 7.25% senior notes due 2019 differs from the fixed interest rate due to the amortization of the related premium on the notes.

Derivative Fair Value Reconciliation

The table below sets forth the changes that occurred in the fair values of our derivative instruments during the nine months ended September 30, 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 and natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period. Actual gains and losses recognized related to our commodity derivative instruments will likely differ from those estimated at September 30, 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 increase (decrease) in fair value	673			(175		)	498
Net contract gains realized	(9,688		)	(12,885		)	(22,573		)
As of September 30, 2013	$	9,899		$	—		$	9,899

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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, Victor A. Wind, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the quarterly period ended September 30, 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 September 30, 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 fiscal year ended December 31, 2012, as updated by Part II, Item 1, of the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013.

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 third 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
July 2013	4,523	$	4.35	—	—
August 2013	—	—		—	—
September 2013	4,575	5.64		—	—
Third Quarter Total	9,098	$	5.00	—	—

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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, No. 5, and No. 6, incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-4 for Forest Oil Corporation filed June 4, 2013 (File No. 333-189064).

4.1			First Amendment to Third Amended and Restated Credit Agreement, dated as of September 12, 2013, among Forest Oil Corporation, the lenders signatory thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed September 18, 2013 (File No. 001-13515).

10.1			Agreement for Purchase and Sale of Assets, dated as of October 3, 2013, by and between Forest Oil Corporation, Forest Oil Permian Corporation, and Templar Energy LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 4, 2013 (File No. 001-13515).

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

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

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

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

101.INS++			XBRL Instance Document.

101.SCH++			XBRL 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)

November 5, 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/ VICTOR A. WIND
		Victor A. Wind Executive Vice President and Chief Financial Officer (on behalf of the Registrant and as Principal Financial Officer)

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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, No. 5, and No. 6, incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-4 for Forest Oil Corporation filed June 4, 2013 (File No. 333-189064).

4.1			First Amendment to Third Amended and Restated Credit Agreement, dated as of September 12, 2013, among Forest Oil Corporation, the lenders signatory thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed September 18, 2013 (File No. 001-13515).

10.1			Agreement for Purchase and Sale of Assets, dated as of October 3, 2013, by and between Forest Oil Corporation, Forest Oil Permian Corporation, and Templar Energy LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 4, 2013 (File No. 001-13515).

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

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

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

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

101.INS++			XBRL Instance Document.

101.SCH++			XBRL 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.