Edgar Filing: FOREST OIL CORP

FST-03.31.2014-10Q



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

__________________________________________________

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2014



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

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

As of May 2, 2014 there were 119,028,774 shares of the registrant’s common stock, par value $.10 per share, outstanding.

Table of Contents

FOREST OIL CORPORATION

INDEX TO FORM 10-Q

March 31, 2014



Part I—FINANCIAL INFORMATION	1
Item 1—Financial Statements	1
Condensed Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	1
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013	2
Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2014 and 2013	3
Condensed Consolidated Statement of Shareholders’ Equity for the Three Months Ended March 31, 2014	4
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	5
Notes to Condensed Consolidated Financial Statements	6
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3—Quantitative and Qualitative Disclosures About Market Risk	37
Item 4—Controls and Procedures	39
Part II—OTHER INFORMATION	40
Item 1—Legal Proceedings	40
Item 1A—Risk Factors	40
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6—Exhibits	42
Signatures	43

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands, Except Share Amounts)



	March 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	48,328		$	66,192
Accounts receivable	32,840			35,654
Derivative instruments	713			5,192
Other current assets	23,871			6,756
Total current assets	105,752			113,794
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $8,480,853 and $8,460,589	776,413			753,079
Unproved	54,612			53,645
Net oil and natural gas properties	831,025			806,724
Other property and equipment, net of accumulated depreciation and amortization of $46,991 and $50,058	10,693			11,845
Net property and equipment	841,718			818,569
Deferred income taxes	1,762			2,230
Goodwill	134,434			134,434
Derivative instruments	2,216			400
Other assets	16,305			48,525
	$	1,102,187		$	1,117,952
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	149,525		$	141,107
Accrued interest	13,445			6,654
Derivative instruments	9,598			4,542
Deferred income taxes	1,762			2,230
Other current liabilities	5,847			12,201
Total current liabilities	180,177			166,734
Long-term debt	800,171			800,179
Asset retirement obligations	24,337			22,629
Derivative instruments	672			—
Other liabilities	61,945			73,941
Total liabilities	1,067,302			1,063,483
Shareholders’ equity:
Preferred stock, none issued and outstanding	—			—
Common stock, 119,099,106 and 119,399,983 shares issued and outstanding	11,910			11,940
Capital surplus	2,556,277			2,554,997
Accumulated deficit	(2,523,077		)	(2,502,070		)
Accumulated other comprehensive loss	(10,225		)	(10,398		)
Total shareholders’ equity	34,885			54,469
	$	1,102,187		$	1,117,952

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands, Except Per Share Amounts)



	Three Months Ended
	March 31,
	2014			2013
Revenues:
Oil, natural gas, and natural gas liquids sales	$	64,457		$	118,042
Interest and other	737			132
Total revenues	65,194			118,174
Costs, expenses, and other:
Lease operating expenses	14,510			21,204
Production and property taxes	3,225			2,216
Transportation and processing costs	2,515			3,280
General and administrative	8,240			20,014
Depreciation, depletion, and amortization	21,415			48,543
Interest expense	16,011			36,128
Realized and unrealized losses on derivative instruments, net	12,851			25,580
Other, net	8,648			28,820
Total costs, expenses, and other	87,415			185,785
Loss before income taxes	(22,221		)	(67,611		)
Income tax (benefit) expense	(1,214		)	337
Net loss	$	(21,007	)	$	(67,948	)

Basic loss per common share	$	(.18	)	$	(.59	)
Diluted loss per common share	$	(.18	)	$	(.59	)

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In Thousands)



	Three Months Ended
	March 31,
	2014			2013
Net loss	$	(21,007	)	$	(67,948	)
Other comprehensive income:
Defined benefit postretirement plans - amortization of actuarial losses, net of tax	173			342
Total other comprehensive income	173			342

Total comprehensive loss	$	(20,834	)	$	(67,606	)

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

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
	Shares		Amount			Capital Surplus			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balances at December 31, 2013	119,400		$	11,940		$	2,554,997		$	(2,502,070	)	$	(10,398	)	$	54,469
Employee stock purchase plan	40		4			61			—			—			65
Restricted stock issued, net of forfeitures	(216	)	(22		)	22			—			—			—
Amortization of stock-based compensation	—		—			1,600			—			—			1,600
Other, net	(125	)	(12		)	(403		)	—			—			(415		)
Net loss	—		—			—			(21,007		)	—			(21,007		)
Other comprehensive income	—		—			—			—			173			173
Balances at March 31, 2014	119,099		$	11,910		$	2,556,277		$	(2,523,077	)	$	(10,225	)	$	34,885

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)



	Three Months Ended
	March 31,
	2014			2013
Operating activities:
Net loss	$	(21,007	)	$	(67,948	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	21,415			48,543
Unrealized losses on derivative instruments, net	8,391			38,311
Stock-based compensation expense	794			3,647
Loss on debt extinguishment	—			25,223
Other, net	1,874			2,140
Changes in operating assets and liabilities:
Accounts receivable	135			265
Other current assets	(1,764		)	(1,109		)
Accounts payable and accrued liabilities	(11,533		)	(14,697		)
Accrued interest and other	10,541			(53		)
Net cash provided by operating activities	8,846			34,322
Investing activities:
Capital expenditures for property and equipment:
Exploration, development, and leasehold acquisition costs	(46,380		)	(101,665		)
Other property and equipment	(3,520		)	(268		)
Proceeds from sales of assets	2,239			313,805
Net cash (used) provided by investing activities	(47,661		)	211,872
Financing activities:
Proceeds from bank borrowings	—			202,000
Repayments of bank borrowings	—			(127,000		)
Redemption of senior notes	—			(321,315		)
Change in bank overdrafts	21,664			590
Other, net	(713		)	(300		)
Net cash provided (used) by financing activities	20,951			(246,025		)
Net (decrease) increase in cash and cash equivalents	(17,864		)	169
Cash and cash equivalents at beginning of period	66,192			1,056
Cash and cash equivalents at end of period	$	48,328		$	1,225
Cash paid during the period for:
Interest (net of capitalized amounts)	$	8,330		$	33,540
Income taxes (net of refunded amounts)	(5,856		)	(129		)
Non-cash investing activities:
(Decrease) increase in accrued capital expenditures	$	(2,170	)	$	26,303

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

Basis of Presentation

The Condensed Consolidated Financial Statements included herein are unaudited and include the accounts of Forest and its consolidated subsidiaries. All intercompany balances and transactions have been eliminated. In the opinion of management, all adjustments, which are of a normal recurring nature, have been made that are necessary for a fair presentation of the financial position of Forest at March 31, 2014, 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 2014 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, included in Forest’s Annual Report on Form 10-K for the year ended December 31, 2013, previously filed with the Securities and Exchange Commission (“SEC”).

Subsequent Event

On May 5, 2014, Forest entered into an Agreement and Plan of Merger with Sabine Oil & Gas LLC (“Sabine”), under which Forest and Sabine will combine their businesses in an all-stock transaction. Upon the completion of the combination transaction, Forest shareholders will own approximately 26.5% of the new combined entity and Sabine shareholders will own approximately 73.5%. Consummation of the transaction is subject to

Table of Contents

approval by Forest shareholders, regulatory approvals, and other customary closing conditions. The combined entity will be known as Sabine Oil & Gas Corporation and be headquartered in Houston.

(2) EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share is computed using the two-class method by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. The two-class method of computing earnings (loss) per share is required to be used since Forest has participating securities. The two-class method is an earnings allocation formula that determines earnings (loss) per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Holders of restricted stock issued under Forest’s stock incentive plans have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock. Holders of phantom stock units issued to directors under Forest’s stock incentive plans also have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock, while phantom stock units issued to employees do not participate in dividends. Stock options 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 share-settled phantom stock units, 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 three months ended March 31, 2014 and 2013.

Table of Contents

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



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands)
Net loss	$	(21,007	)	$	(67,948	)
Less: net earnings attributable to participating securities	—			—
Net loss for basic and diluted loss per share	$	(21,007	)	$	(67,948	)

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



	Three Months Ended
	March 31,
	2014	2013
	(In Thousands)
Weighted average common shares outstanding during the period for basic loss per share	116,838	115,655
Dilutive effects of potential common shares	—	—
Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted loss per share	116,838	115,655

(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.

Table of Contents

Compensation Costs

The table below sets forth stock-based compensation for the three months ended March 31, 2014 and 2013, and the remaining unamortized amounts and weighted average amortization period as of March 31, 2014.



	Restricted Stock			Performance Units			Phantom Stock Units			Total⁽¹⁾⁽²⁾
	(In Thousands)
Three Months Ended March 31, 2014:
Total stock-based compensation costs	$	1,571		$	2		$	175		$	1,748
Less: stock-based compensation costs capitalized	(799		)	(6		)	(114		)	(919		)
Stock-based compensation costs expensed	$	772		$	(4	)	$	61		$	829
Unamortized stock-based compensation costs⁽³⁾	$	6,887		$	2,749		$	2,078		$	11,714
Weighted average amortization period remaining	1.3 years			1.7 years			1.7 years			1.5 years
Three Months Ended March 31, 2013:
Total stock-based compensation costs	$	4,235		$	1,628		$	1,262		$	7,125
Less: stock-based compensation costs capitalized	(1,822		)	(473		)	(669		)	(2,964		)
Stock-based compensation costs expensed	$	2,413		$	1,155		$	593		$	4,161

____________________________________________


(1)	Forest also maintains an employee stock purchase plan (which is not included in the table) under which $.03 million and $.1 million of compensation cost was recognized for the three month periods ended March 31, 2014, and 2013, respectively,


(2)	In connection with the divestiture of the South Texas oil and natural gas properties in the first quarter of 2013, Forest incurred $2.0 million ($1.0 million net of capitalized amounts) in stock-based compensation costs due to accelerated vesting of involuntarily terminated employees’ awards. 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.

Stock Options

The following table summarizes stock option activity in the Plans for the three months ended March 31, 2014.



	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In Thousands)⁽¹⁾		Number of Options Exercisable
Outstanding at January 1, 2014	631,206		$	17.21	$	—	631,206
Granted	—		—
Exercised	—		—		—
Cancelled	(171,377	)	13.88
Outstanding at March 31, 2014	459,829		$	18.45	$	—	459,829

____________________________________________


(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.

Table of Contents

Restricted Stock, Performance Units, and Phantom Stock Units

The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Plans for the three months ended March 31, 2014.



	Restricted Stock						Performance Units						Phantom Stock Units
	Number of Shares⁽¹⁾		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)		Number of Units⁽²⁾		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)		Number of Units⁽³⁾		Weighted Average Grant Date Fair Value		Vest Date Fair Value (In Thousands)
Unvested at January 1, 2014	2,790,542		$	10.23			1,511,140		$	8.48			1,924,819		$	6.75
Awarded	1,000		1.82				—		—				67,000		3.51
Vested	(349,118	)	8.68		$	1,166	—		—		$	—	(313,287	)	7.07		$	1,065
Forfeited	(217,173	)	9.85				(170,300	)	9.33				(139,128	)	7.19
Unvested at March 31, 2014	2,225,251		$	10.51			1,340,840		$	8.38			1,539,404		$	6.51

____________________________________________


(1)	Of the unvested restricted stock as of March 31, 2014, 486,385 shares, which were granted in 2013, vest in one-third increments on each of the first three anniversary dates of the grant. All other unvested shares of restricted stock cliff vest on the third anniversary of the date of grant.

(2)

Of the unvested performance units as of March 31, 2014, 598,500, which were granted in 2013, are cash-based and the remaining unvested performance units are share-based. For both cash- and share-based performance units, the actual settlement amount is dependent upon Forest’s relative total shareholder return in comparison to a specified peer group over a thirty-six month performance period. The cash-based performance units are accounted for as a liability within the Condensed Consolidated Financial Statements.

(3)

All of the unvested phantom stock units as of March 31, 2014 must be settled in cash. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements. All of the phantom stock units that vested during the three months ended March 31, 2014 were settled in cash. Of the unvested phantom stock units as of March 31, 2014, (i) 136,619 were granted in 2011 and 527,785 were granted in 2013 and vest in one-third increments on each of the first three anniversaries of the grant date, (ii) 493,000 were granted in 2013 and 67,000 were granted in 2014 and cliff vest on the third anniversary of the grant date, (iii) and 270,000 were granted in 2012 and 45,000 were granted in 2013 and vest over a four-year period in accordance with the following schedule: (a) 10% on the first anniversary of the grant date; (b) 20% on the second anniversary of the grant date; (c) 30% on the third anniversary of the grant date; and (d) 40% on the fourth anniversary of the grant date.

(4) DEBT

The components of debt are as follows:



	March 31, 2014						December 31, 2013
	Principal		Unamortized Premium		Total		Principal		Unamortized Premium		Total
	(In Thousands)
Credit facility	$	—	$	—	$	—	$	—	$	—	$	—
7¼% senior notes due 2019	577,914		170		578,084		577,914		178		578,092
7½% senior notes due 2020	222,087		—		222,087		222,087		—		222,087
Total long-term debt	$	800,001	$	170	$	800,171	$	800,001	$	178	$	800,179

Table of Contents

Bank Credit Facility

As of March 31, 2014, the Company had a $500.0 million 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 $800.0 million, upon agreement between the applicable lenders and Forest.

On March 31, 2014, the Company entered into the Second Amendment to the Credit Facility (the “Second Amendment”), which was effective as of that date. The Second 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 aggregate lender commitments from $1.5 billion to $500.0 million and the borrowing base, which governs Forest’s availability under the Credit Facility, from $400.0 million to $300.0 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, and the November 2013 sale of Forest’s Texas Panhandle properties resulted in a $300.0 million reduction to the borrowing base effective November 25, 2013. The next scheduled semi-annual redetermination of the borrowing base will occur on or about November 1, 2014. 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. Under the Credit Facility, 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. If Forest’s corporate credit ratings issued by Moody’s and Standard & Poor’s meet pre-established levels, the security requirements would cease to apply and, at Forest’s request, the banks would release their liens and security interest on Forest’s properties.

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 Second 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 to be greater than (i) 5.75 to 1.00 at the end of the calendar quarters ending March 31, 2014, June 30, 2014 and September 30, 2014, (ii) 5.50 to 1.00 at the end of the calendar quarter ending December 31, 2014, (iii) 5.25 to 1.00 at the end of the calendar quarter ending March 31, 2015, (iv) 5.00 to 1.00 at the end of the calendar quarter ending June 30, 2015, (v) 4.75 to 1.00 at the end of the calendar quarter ending September 30, 2015, and (vi) 4.50 to 1.00 at the end of any calendar quarter ending after September 30, 2015. The Second Amendment also amends the definition of total debt such that, among other things, during any period of four fiscal quarters ending on or before September 30, 2015, any cash proceeds from the sale of any property permitted pursuant to the terms and provisions of the loan documents, that are reported on Forest’s consolidated balance sheet on such date are subtracted from total debt.

Table of Contents

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 March 31, 2014, as calculated in accordance with the Credit Facility, was 4.46.

At March 31, 2014, there were no outstanding borrowings under the Credit Facility 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 March 31, 2014 and 2013, Forest capitalized $4.6 million and $12.3 million, respectively, of general and administrative costs (including stock-based compensation). During the three months ended March 31, 2013, Forest capitalized $.2 million of interest costs attributed to unproved properties. No interest costs were capitalized during the three months ended March 31, 2014.

Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, geographic and geologic data obtained relating to the properties, and estimated discounted future net cash flows from the properties. Estimated discounted future net cash flows are based on discounted future net revenues associated with probable and possible reserves, risk adjusted as appropriate. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.

The Company performs a ceiling test each quarter on a country-by-country basis under the full cost method of accounting. The ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or 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 three months ended March 31, 2014, 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 March 31, 2014, 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.

Table of Contents

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. A net gain was recognized on the Panhandle divestiture, which occurred in the fourth quarter of 2013. See “Divestitures” below for more information on the Panhandle divestiture.

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

Texas Panhandle

In October 2013, Forest entered into an agreement to sell all of its oil and natural gas properties located in the Texas Panhandle for $1.0 billion in cash. This divestiture closed on November 25, 2013 and Forest has received $965.1 million in net proceeds to date, with the purchase price having been adjusted to, among other things, reflect an economic effective date of October 1, 2013. As of March 31, 2014, there is $32.9 million remaining in escrow, which Forest may receive as consents-to-assign are received and further post-closing title curative work is completed. Of the $32.9 million escrow balance, $10.0 million supports post-closing indemnities that Forest may owe to the buyer under the terms of the purchase and sale agreement. Any of the $10.0 million remaining in escrow at the one-year anniversary of the closing will be paid to Forest. Forest used a portion of the Panhandle divestiture proceeds to repay the balance outstanding on its credit facility and to redeem $700.0 million aggregate principal amount of its 7¼% senior notes due 2019 and 7½% senior notes due 2020.

In connection with the Panhandle divestiture, Forest incurred exit costs consisting of one-time employee termination benefits and other associated costs, as shown in the table below, which includes a reconciliation of the beginning and ending liability balances for these exit costs for the three months ended March 31, 2014.



	One-Time Employee Termination Benefits			Other Associated Costs⁽¹⁾			Total
	(In Thousands)
Total expected amount⁽²⁾	$	4,612		$	7,967		$	12,579
Total incurred through March 31, 2014⁽³⁾	4,554			7,967			12,521

Liability balance as of December 31, 2013	$	1,095		$	5,840		$	6,935
Costs incurred⁽³⁾	544			—			544
Costs paid	(1,057		)	(5,757		)	(6,814		)
Liability balance as of March 31, 2014⁽⁴⁾	$	582		$	83		$	665

____________________________________________


(1)	Other associated costs consist of financial advisor fees and retention bonuses paid to certain employees.


(2)	Of the $12.6 million total expected costs, the remaining $.1 million will be accrued in the second quarter of 2014 over the remaining retention period of the affected employees.

(3)

Of the $12.5 million costs incurred, (i) $5.5 million was recognized in “General and administrative” expense, $5.0 million during the year ended December 31, 2013 and $.5 million during the quarter ended March 31, 2014, (ii) $5.8 million was recognized in “Other, net” during the year ended December 31, 2013, and (iii) $1.2 million was capitalized in “Oil and natural gas properties” pursuant to the full cost method of accounting, $1.1 million during the year ended December 31, 2013 and the remainder during the quarter ended March 31, 2014.


(4)	The March 31, 2014 estimated liability balance is included in “Accounts payable and accrued liabilities” in the Condensed Consolidated Balance Sheet, and Forest expects it will be paid in the second quarter of 2014.

Table of Contents

The proved reserves associated with the Panhandle divestiture represented more than 25% of Forest’s total proved reserves at the time the divestiture closed. Forest concluded that accounting for the divestiture as an adjustment of capitalized costs would significantly alter the relationship between capitalized costs and proved reserves. Therefore, a gain was recognized on the divestiture. The net gain recognized on the divestiture for the year ended December 31, 2013 was $193.0 million. A net loss of $.8 million was recognized for the three months ended March 31, 2014 as customary post-closing purchase price adjustments were made.

South Texas

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 connection with this divestiture, Forest incurred one-time employee termination benefit costs of $7.5 million ($5.7 million net of capitalization), which are included in “General and administrative” expense in the Condensed Consolidated Statement of Operations for the three months ended March 31, 2013 and were paid in full during 2013.

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.

(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 5% and (0.5)% for the three months ended March 31, 2014, and 2013, respectively, were primarily due to changes in the valuation allowance on Forest’s deferred tax assets.

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

Negative evidence considered by Forest included a three-year cumulative book loss driven primarily by the ceiling test write-downs incurred in 2012 and 2013. 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.

As of December 31, 2013, Forest had a non-current income tax receivable of $20.7 million, which was included in “Other assets”. During the three months ended March 31, 2014, Forest received a refund of $6.6 million including interest income of $.7 million, which reduced this receivable balance by $5.3 million, with the remaining $.6 million recorded as a credit to current income tax expense. The remaining $15.4 million income tax receivable balance was reclassified to current as Forest expects to receive it within the next twelve months, and is included in “Other current assets” in the Condensed Consolidated Balance Sheet at March 31, 2014.

Table of Contents

(7) FAIR VALUE MEASUREMENTS

Forest’s assets and liabilities measured at fair value on a recurring basis at March 31, 2014 and December 31, 2013 are set forth in the table below.



	March 31, 2014		December 31, 2013
	Using Significant Other Observable Inputs (Level 2)⁽¹⁾
	(In Thousands)
Assets:
Derivative instruments⁽²⁾:
Commodity	$	2,929	$	5,592
Liabilities:
Derivative instruments⁽²⁾:
Commodity	$	10,270	$	4,542

____________________________________________

(1)

The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when relevant observable inputs are not available. There were no transfers between levels of the fair value hierarchy during the three months ended March 31, 2014. 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.

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



	March 31, 2014
					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	$	2,929	$	2,929	$	—	$	2,929
Liabilities:
Derivative instruments	10,270		10,270		—		10,270
7¼% senior notes due 2019	578,084		507,842		507,842		—
7½% senior notes due 2020	222,087		194,466		194,466		—

__________________________________________


(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 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.

Table of Contents



	December 31, 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	$	5,592	$	5,592	$	—	$	5,592
Liabilities:
Derivative instruments	4,542		4,542		—		4,542
7¼% senior notes due 2019	578,092		568,147		568,147		—
7½% senior notes due 2020	222,087		224,030		224,030		—

__________________________________________


(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 methods used to determine the fair values of the derivative instruments are discussed above. See also Note 8 for more information on the derivative instruments.

(8) DERIVATIVE INSTRUMENTS

Commodity Derivatives

Forest periodically enters into commodity derivative instruments in order to moderate the effects of wide fluctuations in commodity prices on Forest’s cash flow and to manage its 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 line item “Realized and unrealized losses on derivative instruments, net” in the Condensed Consolidated Statement of Operations.

The table below sets forth Forest’s outstanding commodity swaps as of March 31, 2014.



Commodity Swaps
	Natural Gas (NYMEX HH)			Oil (NYMEX WTI)
Remaining Swap Term	Bbtu Per Day	Weighted Average Hedged Price per MMBtu		Barrels Per Day	Weighted Average Hedged Price per Bbl
April 2014 - December 2014	70	$	4.38	3,500	$	95.34
Calendar 2015	50	4.21		1,000	89.25

The table below sets forth Forest’s outstanding commodity collars as of March 31, 2014.



Commodity Collars
	Natural Gas (NYMEX HH)
Collar Term	Bbtu Per Day	Hedged Floor and Ceiling Price per MMBtu
January 2015 - March 2015	20	$ 4.50/5.31
Calendar 2015	10	4.10/4.30

Table of Contents

In connection with several of its natural gas and oil swaps, Forest granted option instruments (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 March 31, 2014.



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 2016	December 2014	10	$	4.18	—	$	—
Oil Swaptions:
Calendar 2015	December 2014	—	—		3,000	100.00
Calendar 2015	December 2014	—	—		1,000	106.00
Calendar 2015	December 2014	—	—		1,000	99.00
Calendar 2016	December 2015	—	—		1,000	98.00
Oil Put Options:
Monthly Calendar 2014	Monthly Calendar 2014	—	—		2,000	70.00

Fair Value and Gains and Losses

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



	March 31, 2014		December 31, 2013
	(In Thousands)
Current assets:
Derivative instruments:
Commodity	$	713	$	5,192
Long-term assets:
Derivative instruments:
Commodity	$	2,216	$	400
Current liabilities:
Derivative instruments:
Commodity	$	9,598	$	4,542
Long-term liabilities:
Derivative instruments:
Commodity	$	672	$	—

Table of Contents

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
	March 31,
	2014		2013
	(In Thousands)
Commodity derivatives:
Realized losses (gains)	$	4,460	$	(9,649	)
Unrealized losses	8,391		35,161
Interest rate derivatives:
Realized gains	—		(3,082		)
Unrealized losses	—		3,150
Realized and unrealized losses on derivative instruments, net	$	12,851	$	25,580

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 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 March 31, 2014, all but one of Forest’s derivative counterparties are lenders, or affiliates of lenders, under the Credit Facility. The terms of the Credit Facility provide that any security granted by Forest thereunder shall also extend to and be available to those lenders that are counterparties to derivative transactions. None of these counterparties requires collateral beyond that already pledged under the Credit Facility. The remaining counterparty, a purchaser of Forest’s natural gas production, generally owes money to Forest and therefore does not require collateral under the ISDA Master Agreement and Schedule it has executed with Forest.

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

The majority of Forest’s derivative counterparties are financial institutions that are engaged in similar activities and have similar economic characteristics that, in general, could cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions. Forest does not require the posting of collateral for its benefit under its derivative agreements. However, the ISDA Master Agreements and Schedules

Table of Contents

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 $.3 million at March 31, 2014. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net obligations due to it under the derivative agreements. At March 31, 2014, Forest owed a net derivative liability to its counterparties, the fair value of which was $7.7 million. In the absence of netting provisions, at March 31, 2014, Forest would be exposed to a risk of loss of $2.9 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $10.3 million.

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



	Derivative Assets
	March 31, 2014			December 31, 2013
	(In Thousands)
Gross amounts of recognized assets	$	2,929		$	5,592
Gross amounts offset in the balance sheet	—			—
Net amounts of assets presented in the balance sheet	2,929			5,592
Gross amounts not offset in the balance sheet:
Derivative instruments	(2,582		)	(1,049		)
Cash collateral received	—			—
Net amount	$	347		$	4,543



	Derivative Liabilities
	March 31, 2014			December 31, 2013
	(In Thousands)
Gross amounts of recognized liabilities	$	10,270		$	4,542
Gross amounts offset in the balance sheet	—			—
Net amounts of liabilities presented in the balance sheet	10,270			4,542
Gross amounts not offset in the balance sheet:
Derivative instruments	(2,582		)	(1,049		)
Cash collateral pledged	—			—
Net amount	$	7,688		$	3,493

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. However, the legislation could have a substantial impact on Forest’s counterparties and increase the cost of Forest’s derivative agreements in the future.

Table of Contents

(9) COSTS, EXPENSES, AND OTHER

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



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands)
Accretion of asset retirement obligations	$	513		$	1,244
Write-off of debt issuance costs	3,323			—
Loss on debt extinguishment	—			25,223
Loss on asset disposition, net	794			—
Rig stacking/lease termination	5,184			3,038
Other, net	(1,166		)	(685		)
	$	8,648		$	28,820

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.

Write-off of Debt Issuance Costs

On March 31, 2014 Forest entered into the Second Amendment to the Credit Facility, which was effective as of that date. The Second Amendment reduced aggregate lender commitments from $1.5 billion to $500.0 million, necessitating a proportionate write-off of $3.3 million in unamortized debt issuance costs associated with the Credit Facility prior to the Second Amendment.

Loss on Debt Extinguishment

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

Loss on Asset Disposition, Net

In October 2013, Forest entered into an agreement to sell all of its oil and natural gas properties located in the Texas Panhandle for $1.0 billion in cash. This transaction closed in November 2013 and Forest has received net proceeds to-date of $965.1 million, after customary purchase price adjustments. For the year ended December 31, 2013, Forest recognized a net gain of $193.0 million on this divestiture. A net loss of $.8 million was recognized for the three months ended March 31, 2014 as customary post-closing purchase price adjustments were made.

Rig Stacking/Lease Termination

Rig stacking comprises the expenses incurred to operate and maintain drilling rigs, which Forest has historically leased under non-cancelable operating leases, that are not being utilized on capital projects. The three months ended March 31, 2014 includes cash expenses of $5.0 million related to the early termination of the operating leases on seven drilling rigs as well as $3.8 million of rig stacking expenses, primarily on those seven rigs

Table of Contents

prior to the lease termination date, for total cash expenses of $8.8 million. Also included in the lease termination expense for the three months ended March 31, 2014, is a non-cash write-off of $2.4 million primarily related to rig improvements Forest had made that were transferred with the drilling rigs at the lease termination date. Partially offsetting these expenses is a non-cash write-off of $6.1 million of unamortized deferred gains related to the drilling rigs whose leases were terminated. The deferred gains were initially recognized upon the sale leaseback transactions of these rigs in 2007 and 2010 and were being amortized over the lives of the leases. During the three months ended March 31, 2013, Forest incurred rig stacking expenses of $4.2 million.

(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 months ended March 31, 2014 consists of actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost, which is included in the line item “General and administrative” in the Condensed Consolidated Statements of Operations.

The components of other comprehensive income, both before-tax and net-of-tax, for the three months ended March 31, 2014 are as follows:



	Before-Tax		Tax (Expense) / Benefit			Net-of-Tax
	(In Thousands)
Three Months Ended March 31, 2014:
Defined benefit postretirement plans
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost	$	173	$	—		$	173
Other comprehensive income	$	173	$	—	⁽¹⁾	$	173

____________________________________


(1)	Tax expense is offset by an equal decrease in the valuation allowance.

The change in the accumulated balance of other comprehensive income (loss) during the three months ended March 31, 2014 is as follows:



	Accumulated Other Comprehensive Income (Loss)⁽¹⁾
	(In Thousands)
Defined benefit postretirement plans
Balance at December 31, 2013	$	(10,398	)

Amounts reclassified from accumulated other comprehensive loss	173
Other comprehensive income	173

Balance at March 31, 2014	$	(10,225	)

____________________________________


(1)	All amounts are net of tax.

Table of Contents

(11) NEW ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360)—Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” (“ASU 2014-08”). ASU 2014-08 changes the requirements for reporting discontinued operations and requires expanded disclosures for discontinued operations and individually significant components of an entity that either have been disposed of or are classified as held for sale, but do not qualify for discontinued operations reporting. Only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. ASU 2014-08 is effective for annual periods, and interim periods within those years, beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted, but only for disposals or classifications as held for sale that have not been reported in financial statements previously issued or available for issuance. Forest adopted ASU 2014-08 during the quarter ended March 31, 2014 and there was no impact to its consolidated financial statements.

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 2013 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 reportable geographical segment - the United States. Our core operational areas are in the Eagle Ford in South Texas and the Ark-La-Tex region in Texas, Louisiana, and Arkansas.

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 for $1 billion in cash. This transaction closed in November 2013 and we have received net cash proceeds of $965 million through March 31, 2014, after customary purchase price adjustments. As of March 31, 2014, $33 million remains in escrow, which we may receive as consents-to-assign are received and title curative work is completed. Of the $33 million escrow balance, $10 million supports post-closing indemnities that we may owe to the buyer under the terms of the purchase and sale agreement. We will receive any of the $10 million remaining in escrow at the one-year anniversary of the closing. 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 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. We used the proceeds from these property divestitures to reduce our debt. These property divestitures affect the comparability of the results of our operations between the three months ended March 31, 2014 and the three months ended March 31, 2013 presented herein.

Table of Contents

On May 5, 2014, we entered into an Agreement and Plan of Merger with Sabine Oil & Gas LLC (“Sabine”), under which Forest and Sabine will combine their businesses in an all-stock transaction. Upon the completion of the combination transaction, Forest shareholders will own approximately 26.5% of the new combined entity and Sabine shareholders will own approximately 73.5%. Consummation of the transaction is subject to approval by Forest shareholders, regulatory approvals, and other customary closing conditions. The combined entity will be known as Sabine Oil & Gas Corporation and be headquartered in Houston.

RESULTS OF OPERATIONS

Table of Contents

For the three months ended March 31, 2014, we recognized a net loss of $21 million compared to a net loss of $68 million for the three months ended March 31, 2013. Adjusted EBITDA, which is a measure used by management, securities analysts, and investors that consists of net loss before interest expense, income taxes, depreciation, depletion, and amortization, as well as other items including unrealized gains and losses on derivative instruments, was $35 million for the three months ended March 31, 2014 and $94 million for the three months ended March 31, 2013. The $60 million decrease was primarily due to the property divestitures referenced above under “Recent Events.” Adjusted EBITDA is a performance measure 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 our reported net loss, the most directly comparable financial measure calculated and presented in accordance with GAAP.

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

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

Oil, natural gas, and natural gas liquids sales volumes, revenues, and average sales prices for the three months ended March 31, 2014 and 2013 are set forth in the table below.



	Three Months Ended
	March 31,
	2014		2013
Sales volumes:
Oil (MBbls)	326		559
Natural gas (MMcf)	6,438		14,332
NGLs (MBbls)	178		698
Totals (MMcfe)	9,462		21,874
Revenues (in thousands):
Oil	$	30,332	$	53,962
Natural gas	28,171		42,658
NGLs	5,954		21,422
Totals	$	64,457	$	118,042
Average sales price per unit:
Oil ($/Bbl)	$	93.04	$	96.53
Natural gas ($/Mcf)	4.38		2.98
NGLs ($/Bbl)	33.45		30.69
Totals ($/Mcfe)	$	6.81	$	5.40

Our equivalent sales volumes were 9.5 Bcfe for the three months ended March 31, 2014 and 21.9 Bcfe for the three months ended March 31, 2013. Of the 12.4 Bcfe decrease in equivalent sales volumes in the first quarter of 2014 compared to the first quarter of 2013, approximately 11.6 Bcfe, or 93%, was due to divestitures of producing oil and natural gas properties in South Texas and the Texas Panhandle, which occurred in February 2013 and November 2013, respectively. The remaining .8 Bcfe decrease is due to a 1.2 Bcfe decrease in natural gas production

Table of Contents

in the Ark-La-Tex region which was partially offset by an increase in oil production primarily in the Eagle Ford. Our liquids sales volumes have increased 16% to 32% of total equivalent sales volumes during the first quarter 2014 as compared to 25% in the first quarter 2013, excluding the effects of property divestitures.

Revenues from oil, natural gas, and NGLs were $64 million in the first quarter of 2014 compared to $118 million in the first quarter of 2013. Of the $54 million decrease, approximately $61 million was a result of the property divestitures discussed above. This decrease was partially offset by a 24% increase in the average sales price per Mcfe realized on production from the properties we’ve retained, from $5.52 per Mcfe in the first quarter of 2013 to $6.81 per Mcfe in the first quarter of 2014.

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.

Production Expense

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



	Three Months Ended
	March 31,
	2014		2013
	(In Thousands, Except Per Mcfe Data)
Production expense:
Lease operating expenses	$	14,510	$	21,204
Production and property taxes	3,225		2,216
Transportation and processing costs	2,515		3,280
Production expense	$	20,250	$	26,700
Production expense per Mcfe:
Lease operating expenses	$	1.53	$	.97
Production and property taxes	.34		.10
Transportation and processing costs	.27		.15
Production expense per Mcfe	$	2.14	$	1.22

Lease Operating Expenses

Lease operating expenses in the first quarter of 2014 were $15 million, or $1.53 per Mcfe, compared to $21 million, or $.97 per Mcfe, in the first quarter of 2013. Lease operating expenses decreased $7 million in the three month period ended March 31, 2014 compared to the corresponding period in 2013 due primarily to property divestitures that occurred in February 2013 and November 2013. The lease operating costs incurred for these divested properties was $11 million in the first quarter of 2013. The net increase in lease operating expenses of $4 million between the two periods excluding the property divestitures was primarily due to increased costs related to our oil production, namely saltwater disposal and chemical treatment costs. Based on the energy-equivalent ratio of six Mcf of natural gas to one barrel of oil, oil production typically has higher per-unit lease operating costs than does natural gas production. However, because the market price of oil relative to natural gas is currently well in excess of the standard energy equivalent six-to-one ratio, the increase in lease operating expense associated with an increase in oil production is typically more than offset by the additional revenues realized from oil sales.

Production and Property Taxes

Production and property taxes, consisting primarily of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 5.0% and 1.9% of oil, natural gas, and NGL revenues for the three-month periods ended March 31, 2014 and 2013, respectively. The increase in the percentage from the first quarter of 2013 to the first quarter of 2014 was due to the approval of reduced severance tax rates on several wells in the Texas Panhandle during the first quarter of 2013 for which refunds were accrued to recover the severance taxes paid on these wells prior to the approval of the reduced rate. Excluding the production and property taxes and revenues related to the South Texas and Texas Panhandle divestitures, production and property taxes were 4.5% of oil, natural gas, and NGL revenues for the three months ended March 31, 2013. Normal fluctuations also occur in this percentage

Table of Contents

between periods based upon changes in tax rates and changes in the assessed values of oil and gas properties and equipment for purposes of ad valorem taxes.

Transportation and Processing Costs

Transportation and processing costs in the first quarter of 2014 were $3 million, or $.27 per Mcfe, compared to $3 million, or $.15 per Mcfe, in the first quarter of 2013. Although transportation and processing costs were consistent between the periods presented, the per-unit cost increased $.12 per Mcfe to $.27 per Mcfe. This increase was primarily due to the divestitures of producing oil and natural gas properties in South Texas and the Texas Panhandle, which occurred in February 2013 and November 2013, respectively. These properties had minimal transportation costs associated with them, and as a result the divestitures had minimal impact in reducing transportation and processing costs recorded in the first quarter of 2014. When excluding both the transportation and processing costs as well as the sales volumes related to the divested properties from the first quarter of 2013, transportation and processing costs were $.29 per Mcfe compared to $.27 per Mcfe recorded for the three months ended March 31, 2014.

General and Administrative Expense

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



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands)
Stock-based compensation costs	$	1,774		$	7,224
Stock-based compensation costs capitalized	(919		)	(2,964		)
	855			4,260

Other general and administrative costs	11,024			25,088
Other general and administrative costs capitalized	(3,639		)	(9,334		)
	7,385			15,754

General and administrative expense	$	8,240		$	20,014

General and administrative expense was $8 million in the first quarter of 2014 compared to $20 million in the first quarter of 2013. For the first quarter of 2014, other general and administrative costs include $1 million ($1 million net of capitalized amounts) in employee-related asset divestiture costs related to the Texas Panhandle divestiture and the resulting reduction in employee headcount, most of which occurred in the fourth quarter of 2013, with some employees staying throughout the first quarter of 2014 during a transition period post-divestiture. For the first quarter of 2013, other general and administrative costs include $8 million ($6 million net of capitalized amounts) in employee-related asset divestiture costs related to the South Texas divestiture and the resulting reduction in employee headcount. Of the $8 million decrease in other general and administrative costs (net of costs capitalized) in the first quarter of 2014 compared to the first quarter of 2013, $5 million was attributable to the decrease in employee-related asset divestiture costs discussed above and the remaining $3 million was primarily attributable to decreased salaries and wages due to decreased employee headcount.

Table of Contents

Stock-based compensation costs, net of costs capitalized, decreased $3 million during the first quarter of 2014 as compared to the first quarter of 2013. The decrease was primarily due to a reduction in employee headcount and a decrease in the Company’s stock price from the first quarter of 2013 to the first quarter of 2014. In addition, the first quarter of 2013 also included $1 million more in accelerated stock-based compensation costs related to reductions in employee headcount as a result of asset divestitures than did the first quarter of 2014.

The percentage of general and administrative costs capitalized under the full cost method of accounting ranged from 36% to 38% in the periods presented.

Depreciation, Depletion, and Amortization

The table below sets forth the components of depreciation, depletion, and amortization expense for the periods indicated.



	Three Months Ended March 31,
	2014				2013
	In Thousands		$/Mcfe		In Thousands		$/Mcfe
Depletion	$	20,264	$	2.14	$	47,538	$	2.17
Depreciation	1,151		0.12		1,005		0.05
Depreciation, depletion, and amortization	$	21,415	$	2.26	$	48,543	$	2.22

Depreciation, depletion, and amortization expense (“DD&A”) in the first quarter of 2014 was $21 million, or $2.26 per Mcfe, compared to $49 million, or $2.22 per Mcfe, in the first quarter of 2013.

The decrease in our depletion rate per Mcfe in the first quarter of 2014 as compared to the depletion rate per Mcfe in the first quarter of 2013 is due to the decrease in our depletable basis partially offset by the decrease in our oil and natural gas reserves, with such decreases primarily attributable to our property divestitures.

Interest Expense

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



	Three Months Ended
	March 31,
	2014		2013
	(In Thousands)
Interest costs	$	16,011	$	36,319
Interest costs capitalized	—		(191		)
Interest expense	$	16,011	$	36,128

Interest expense was $16 million and $36 million for the three months ended March 31, 2014 and 2013, respectively. Interest expense decreased $20 million in the first quarter 2014 as compared to the first quarter 2013. This decrease was comprised of the following: (i) $6 million due to the redemption of the $300 million of 8½% senior notes in March 2013, (ii) $13 million due to the redemption of $700 million of 7¼% senior notes and 7½% senior notes in November 2013, and (iii) $1 million due to decreased borrowings outstanding under our credit facility during 2014. 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.

Table of Contents

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. Realized and unrealized gains and losses on derivative instruments vary from period to period based on the specific terms of the derivative instruments to which we are a party during the period and based on the third-party indices’ settlement prices during the period. See Note 7 and Note 8 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.



	Three Months Ended
	March 31,
	2014		2013
	(In Thousands)
Realized losses (gains) on derivative instruments, net:
Oil	$	1,032	$	(428	)
Natural gas	3,428		(9,221		)
Interest	—		(3,082		)
Subtotal realized losses (gains) on derivative instruments, net	4,460		(12,731		)
Unrealized losses (gains) on derivative instruments, net:
Oil	2,037		(308		)
Natural gas	6,354		35,469
Interest	—		3,150
Subtotal unrealized losses on derivative instruments, net	8,391		38,311
Realized and unrealized losses on derivative instruments, net	$	12,851	$	25,580

Other, Net

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



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands)
Accretion of asset retirement obligations	$	513		$	1,244
Write-off of debt issuance costs	3,323			—
Loss on debt extinguishment	—			25,223
Loss on asset disposition, net	794			—
Rig stacking/lease termination	5,184			3,038
Other, net	(1,166		)	(685		)
	$	8,648		$	28,820

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

Table of Contents

Income Tax

The table below sets forth total income tax and the effective income tax rates for the periods indicated.



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands, Except Percentages)
Current income tax	$	(1,214	)	$	337
Deferred income tax	—			—
Total income tax (benefit) expense	$	(1,214	)	$	337
Effective income tax rate	5		%	(0.5		)%

Our effective income tax rates were 5% and (0.5)% for the three months ended March 31, 2014 and 2013, respectively. The significant differences between our blended federal and state statutory income tax rate of 36% and our effective income tax rates for the periods shown were primarily due to changes in the valuation allowance placed against our deferred tax assets. See Note 6 to the Condensed Consolidated Financial Statements for more information regarding our income tax valuation allowance.

LIQUIDITY AND CAPITAL RESOURCES

Our exploration, development, and acquisition activities require us to make significant operating and capital expenditures (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 May 2, 2014, we had hedged, via commodity swaps and collars, approximately 33 Bcfe of our total projected 2014 production and approximately 26 Bcfe of our total projected 2015 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 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 $300 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 5.75 to 1.00 as of March 31, 2014. 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 quarter period ended March 31, 2014, as calculated in accordance with the credit facility, was 4.46. We had no borrowings outstanding under the credit facility as of March 31, 2014 and May 2, 2014. 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.

Table of Contents

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 and joint ventures as a means of generating additional cash to fund more attractive capital projects and to 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 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 November 2013, we sold all of our oil and natural gas properties located in the Texas Panhandle for net proceeds to date of $965 million, which we used in November 2013 to redeem $700 million of 7¼% senior notes due 2019 and 7½% senior notes due 2020, and to pay off the outstanding balance on our credit facility. In addition, 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 acreage in exchange for a 50% working interest in that acreage.

We believe that our existing cash, expected cash flows provided by operating activities, and the funds available under the credit facility will be sufficient to fund our normal recurring operating needs and our contractual obligations for a reasonable period of time.

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”), which, as of March 31, 2014, consists of a $500 million credit facility maturing in June 2016. The size of the Credit Facility may be increased by $300 million, to a total of $800 million, upon agreement between us and the applicable lenders. On March 31, 2014, we entered into the Second Amendment to the Credit Facility (the “Second Amendment”), which was effective as of that date. The Second 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 aggregate lender commitments from $1.5 billion to $500 million and the borrowing base, which governs our availability under the Credit Facility, from $400 million to $300 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 next scheduled semi-annual redetermination of the borrowing base will occur on or about November 1, 2014. In addition to the scheduled semi-annual redeterminations, we and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined.

The borrowing base is also subject to automatic adjustments if certain events occur, such as if we or any of our Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that we or any of our Restricted Subsidiaries may issue to refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if we or any of our Restricted Subsidiaries sell oil and natural gas properties 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

Table of Contents

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 and the November 2013 sale of our Texas Panhandle properties resulted in a $300 million reduction to the borrowing base effective November 25, 2013. See Note 5 to the Condensed Consolidated Financial Statements for more information regarding our divestiture activity.

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 Standard & Poor’s 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 Second 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 to be greater than (i) 5.75 to 1.00 at the end of the calendar quarters ending March 31, 2014, June 30, 2014 and September 30, 2014, (ii) 5.50 to 1.00 at the end of the calendar quarter ending December 31, 2014, (iii) 5.25 to 1.00 at the end of the calendar quarter ending March 31, 2015, (iv) 5.00 to 1.00 at the end of the calendar quarter ending June 30, 2015, (v) 4.75 to 1.00 at the end of the calendar quarter ending September 30, 2015, and (vi) 4.50 to 1.00 at the end of any calendar quarter ending after September 30, 2015. The Second Amendment also amends the definition of total debt such that, among other things, during any period of four fiscal quarters ending on or before September 30, 2015, any cash proceeds from the sale of any property permitted pursuant to the terms and provisions of the loan documents, 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 March 31, 2014, as calculated in accordance with the Credit Facility, was 4.46.

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

At March 31, 2014 and May 2, 2014, there were no outstanding borrowings under the Credit Facility. We had used the Credit Facility for $2 million and $3 million in letters of credit at March 31, 2014 and May 2, 2014, respectively. At May 2, 2014, the unused borrowing amount under the Credit Facility was $297 million. However,

Table of Contents

based on the ratio of total debt to EBITDA discussed above, our borrowing utilization of the Credit Facility is currently limited to approximately $218 million.

Of the $500 million 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 May 2, 2014, 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 (used) provided by investing activities, and net cash provided (used) by financing activities for the three months ended March 31, 2014 and 2013 were as follows:



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands)
Net cash provided by operating activities	$	8,846		$	34,322
Net cash (used) provided by investing activities	(47,661		)	211,872
Net cash provided (used) by financing activities	20,951			(246,025		)

Net cash provided by operating activities is primarily affected by sales volumes and commodity prices, net of the effects of settlements of our derivative instruments and changes in working capital. The decrease in net cash provided by operating activities in the three months ended March 31, 2014 compared to the three months ended March 31, 2013, was primarily due to (i) decreased revenues in 2014 as compared to 2013, which was caused primarily by lower sales volumes attributable to divestitures of oil and natural gas properties in South Texas and the Texas Panhandle, which occurred in February 2013 and November 2013, respectively, and (ii) increased cash expenses related to drilling rig stacking and operating lease terminations in 2014 as compared to 2013 (see Note 9 to the Condensed Consolidated Financial Statements for more information on drilling rig stacking and lease terminations). These decreases were partially offset by (i) lower production expense in 2014 as compared to 2013, which is attributable to the oil and natural gas properties divestitures, and (ii) a decreased investment in working capital in 2014 as compared to 2013.

Table of Contents

The components of net cash (used) provided by investing activities for the three months ended March 31, 2014 and 2013 were as follows:



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands)
Exploration, development, and leasehold acquisition costs⁽¹⁾	$	(46,380	)	$	(101,665	)
Proceeds from sales of assets	2,239			313,805
Other property and equipment	(3,520		)	(268		)
Net cash (used) provided by investing activities	$	(47,661	)	$	211,872

____________________________________________

(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.

Net cash (used) provided 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 change in net cash used by investing activities in the three months ended March 31, 2014 compared to the corresponding period of 2013 was primarily due to a decrease in proceeds from the sale of assets partially offset by a decrease in exploration, development, and leasehold acquisition cost expenditures. Expenditures for the acquisition, exploration, and development of oil and natural gas properties decreased for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013 due to the Texas Panhandle divestiture that occurred in November 2013. Acquisition, exploration, and development expenditures for the Texas Panhandle properties approximated $51 million during the three months ended March 31, 2013. Net cash provided by investing activities in the three months ended March 31, 2013 consisted principally of the net proceeds received for the South Texas divestiture that occurred in February 2013.

Net cash provided by financing activities of $21 million during the three months ended March 31, 2014 consisted primarily of a change in bank overdrafts of $22 million. Net cash used by financing activities of $246 million during the three months ended March 31, 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 $75 million.

Table of Contents

Capital Expenditures

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



	Three Months Ended
	March 31,
	2014		2013
	(In Thousands)
Exploration, development, and acquisition costs:
Direct costs:
Exploration and development	$	41,242	$	115,823
Leasehold acquisitions	88		2,605
Overhead capitalized	4,558		12,298
Interest capitalized	—		191
Total capital expenditures⁽¹⁾	$	45,888	$	130,917

____________________________________________

(1)

Total capital expenditures include cash expenditures, accrued expenditures, and non-cash capital expenditures including stock-based compensation capitalized under the full cost method of accounting. Total capital expenditures also include changes in estimated discounted asset retirement obligations of $(.2) million and $.3 million recorded during the three months ended March 31, 2014 and 2013, respectively.

We have established a drilling and completion capital budget of $260 million to $270 million (excluding property acquisitions, capitalized overhead, and changes in asset retirement obligations) for 2014, which will be allocated approximately 64% to Ark-La-Tex and 36% to Eagle Ford. We expect to fund these capital expenditures with a combination of cash from operations and borrowings under our Credit Facility. 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. In addition, capital expenditures will depend on availability under our Credit Facility.

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;

Table of Contents


•	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;


•	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;


•	our ability to consummate our proposed combination transaction with Sabine;


•	the timing of the consummation of the proposed combination transaction with Sabine; and


•	the ability of the combined entity to integrate our operations and the operations of Sabine and achieve or realize any anticipated benefits, savings, or growth of the proposed combination transaction.

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 2013 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.

Table of Contents

RECONCILIATION OF NON-GAAP MEASURE

Adjusted EBITDA

In addition to reporting net loss as defined under GAAP, we also present adjusted earnings before interest, income taxes, depreciation, depletion, amortization, and certain other items (“Adjusted EBITDA”), which is a non-GAAP performance measure. Adjusted EBITDA consists of net loss before interest expense, income taxes, depreciation, depletion, and amortization, unrealized gains and losses on derivative instruments (which represent changes in the fair values of the derivative instruments), accretion of asset retirement obligations, and the other items set forth in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to, GAAP measurements, such as net 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 the oil and gas industry. Our management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net loss and revenues, to measure operating performance. The following table provides a reconciliation of net loss, the most directly comparable GAAP measure, to Adjusted EBITDA for the periods presented.



	Three Months Ended
	March 31,
	2014			2013
	(In Thousands)
Net loss	$	(21,007	)	$	(67,948	)
Income tax (benefit) expense	(1,214		)	337
Unrealized losses on derivative instruments, net	8,391			38,311
Interest expense	16,011			36,128
Loss on asset disposition, net	794			—
Write-off of debt issuance costs	3,323			—
Loss on debt extinguishment	—			25,223
Accretion of asset retirement obligations	513			1,244
Depreciation, depletion, and amortization	21,415			48,543
Stock-based compensation	794			3,647
Employee-related asset disposition costs	579			5,821
Rig stacking/lease termination	5,184			3,038
Adjusted EBITDA	$	34,783		$	94,344

The $60 million decrease in Adjusted EBITDA between the two periods was primarily due to the property divestitures discussed under “Overview—Recent Events” at the beginning of this Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Table of Contents

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. The table below sets forth our outstanding swaps as of March 31, 2014.



Commodity Swaps
	Natural Gas (NYMEX HH)						Oil (NYMEX WTI)
Remaining Swap Term	Bbtu per Day	Weighted Average Hedged Price per MMBtu		Fair Value (In Thousands)			Barrels per Day	Weighted Average Hedged Price per Bbl		Fair Value (In Thousands)
April 2014 - December 2014	70	$	4.38	$	(1,675	)	3,500	$	95.34	$	(2,294	)
Calendar 2015	50	4.21		81			1,000	89.25		(231		)

Collars

A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price. The table below sets forth our outstanding collars as of March 31, 2014.



Commodity Collars
	Natural Gas (NYMEX HH)
Collar Term	Bbtu Per Day	Hedged Floor and Ceiling Price per MMBtu	Fair Value (In Thousands)
January 2015 - March 2015	20	$ 4.50/5.31	$	306
Calendar 2015	10	4.10/4.30	(54		)

Table of Contents

Commodity Options

In connection with several of our natural gas and oil swaps, we granted option instruments (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 March 31, 2014.



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 2016	December 2014	10	$	4.18	$	(693	)	—	$	—	$	—
Oil Swaptions:
Calendar 2015	December 2014	—	—		—			3,000	100.00		(1,354		)
Calendar 2015	December 2014	—	—		—			1,000	106.00		(182		)
Calendar 2015	December 2014	—	—		—			1,000	99.00		(513		)
Calendar 2016	December 2015	—	—		—			1,000	98.00		(672		)
Oil Put Options:
Monthly Calendar 2014	Monthly Calendar 2014	—	—		—			2,000	70.00		(60		)

The estimated fair value at March 31, 2014 of all our commodity derivative instruments based on various valuation inputs, including published forward prices, was a net liability of approximately $7 million.

Derivative Fair Value Reconciliation

The table below sets forth the changes that occurred in the fair values of our commodity derivative instruments during the three months ended March 31, 2014, beginning with the fair value of our derivative instruments on December 31, 2013. 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 cash settlements recognized related to our commodity derivative instruments will likely differ from those estimated at March 31, 2014 and will depend exclusively on the price of the commodities on the settlement dates specified by the derivative instruments.



	Fair Value of Derivative Contracts
	(In Thousands)
As of December 31, 2013	$	1,050
Net decrease in fair value	(12,851		)
Net cash settlements paid	4,460
As of March 31, 2014	$	(7,341	)

Table of Contents

Interest Rate Risk

The following table presents principal amounts and related interest rates by year of maturity for senior notes at March 31, 2014.



	2019			2020			Total

Senior notes:
Principal (in thousands)	$	577,914		$	222,087		$	800,001
Fixed interest rate	7.25		%	7.50		%	7.32		%
Effective interest rate⁽¹⁾	7.24		%	7.50		%	7.32		%

____________________________________________


(1)	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.

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 March 31, 2014 (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 the quarterly period ended March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

On March 26, 2014, the judge overseeing the lawsuit, styled Augenbaum v. Lone Pine Resources Inc. et al., granted defendants’ motion to dismiss, with prejudice, for failure to state a claim upon which relief may be granted. The original claim was brought on May 25, 2012, as a purported class action in the Supreme Court of the State of New York, New York County against Forest, Lone Pine, certain of Lone Pine’s current and former directors and officers (the “Individual Defendants”), and certain underwriters (the “Underwriter Defendants”) of Lone Pine’s initial public offering (the “IPO”), which was completed on June 1, 2011. The class action was subsequently removed to the United States District Court for the Southern District of New York. The complaint alleged that Lone Pine’s registration statement and prospectus issued in connection with the IPO contained untrue statements of material fact or omitted to state material facts relating to forest fires that occurred in Northern Alberta in May 2011, the rupture of a third-party oil sales pipeline in Northern Alberta in April 2011, and the impact of those events on Lone Pine, that the alleged misstatements or omissions violated Section 11 of the Securities Act of 1933 (the “Securities Act”), and that Lone Pine, the Individual Defendants, and the Underwriter Defendants are liable for such violations. (The complaint was subsequently amended to drop the allegation regarding the forest fires.) The complaint further alleged that the Underwriter Defendants offered and sold Lone Pine’s securities in violation of Section 12(a)(2) of the Securities Act, and the putative class members seek rescission of the securities purchased in the IPO that they continue to own and rescissionary damages for securities that they have sold. Finally, the complaint asserted a claim against Forest under Section 15 of the Securities Act, alleging that Forest was a “control person” of Lone Pine at the time of the IPO. The complaint alleged that the putative class, which purchased shares of Lone Pine’s common stock pursuant and/or traceable to Lone Pine’s registration statement and prospectus, was damaged when the value of the stock declined in August 2011. Plaintiff has filed notice of intent to appeal.

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, 2013, except as noted above.

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, 2013.

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.

Table of Contents

Issuer Purchases of Equity Securities

The table below sets forth information regarding repurchases of our common stock during the first quarter of 2014. The shares repurchased represent shares of our common stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Forest does not consider this a share buyback program.



Period	Total # of Shares Purchased	Average Price Paid Per Share		Total # of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum # (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs
January 2014	109,181	$	3.43	—	—
February 2014	14,810	2.74		—	—
March 2014	528	1.84		—	—
First Quarter Total	124,519	$	3.34	—	—

Table of Contents

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			Second Amendment to Third Amended and Restated Credit Agreement, dated as of March 31, 2014, 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 April 1, 2014 (File No. 001-13515).

10.1			Forest Oil Corporation 2014 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2014 (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 Exchange Act 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.

Table of Contents

SIGNATURES

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



	FOREST OIL CORPORATION (Registrant)

May 6, 2014	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)

Table of Contents

Exhibit Index



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

3.2			Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, 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			Second Amendment to Third Amended and Restated Credit Agreement, dated as of March 31, 2014, 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 April 1, 2014 (File No. 001-13515).

10.1			Forest Oil Corporation 2014 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2014 (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 Exchange Act or otherwise subject to the liabilities of that section.