Edgar Filing: FOREST OIL CORP

FST-06.30.2014-10Q



	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 June 30, 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 August 14, 2014 there were 119,338,561 shares of the registrant’s common stock, par value $.10 per share, outstanding.

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FOREST OIL CORPORATION

INDEX TO FORM 10-Q

June 30, 2014



Part I—FINANCIAL INFORMATION	1
Item 1—Financial Statements	1
Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	2
Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2014 and 2013	3
Condensed Consolidated Statement of Shareholders’ Equity (Deficit) for the Six Months Ended June 30, 2014	4
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 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	24
Item 3—Quantitative and Qualitative Disclosures About Market Risk	44
Item 4—Controls and Procedures	46
Part II—OTHER INFORMATION	47
Item 1—Legal Proceedings	47
Item 1A—Risk Factors	48
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 6—Exhibits	52
Signatures	54

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EXPLANATORY NOTE

Rule 10-01(d) of Regulation S-X requires that interim financial statements included in quarterly reports on Form 10-Q be reviewed by an independent registered public accountant using professional standards and procedures for conducting such reviews, as established by generally accepted auditing standards, as may be modified or supplemented by the SEC. As previously announced in Item 8.01 of our Current Report on Form 8-K filed on August 11, 2014, our management has determined that certain material weaknesses existed in our internal control over financial reporting at year end 2013. Ernst & Young LLP has reached the same conclusion. Accordingly, our internal control over financial reporting was ineffective at December 31, 2013. Consequently, both management’s assessment and the report of Ernst & Young LLP on internal control over financial reporting as of December 31, 2013 should no longer be relied upon. In addition, our management has determined that Forest’s disclosure controls and procedures were not effective at a reasonable level as of December 31, 2013 and March 31, 2014. To the knowledge of our chief executive officer and chief financial officer, the material weaknesses in internal control over financial reporting did not result in a misstatement of the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2013. However, because the identified material weaknesses relate to our accounting software system, which is a critical component of our financial statement preparation process, Ernst & Young LLP and Forest are performing additional testing of Forest’s financial statements for each of the three years included in our Annual Report Form 10-K for the year ended December 31, 2013. Ernst & Young LLP therefore will be unable to complete a review of the interim consolidated financial statements in accordance with AU sec. 722, Interim Financial Statements (“AU 722”) until such time as the additional testing is completed on our Annual Report on Form 10-K for the ended December 31, 2013. Accordingly, the accompanying consolidated financial statements as of June 30, 2014 and for the three and six months ended June 30, 2014 have not been reviewed by an independent public accountant in accordance with AU 722 and, therefore, this quarterly report on Form 10-Q is deficient.

Section 302 of the Sarbanes-Oxley Act of 2002 requires our chief executive officer and chief financial officer to certify, among other things, that they (i) have designed the internal controls to ensure that material information relating to us and our consolidated subsidiaries is made known to such officers by others within those entities, particularly during the period in which the periodic reports are being prepared, and (ii) have disclosed all significant deficiencies in the design or operation of internal controls which could adversely affect our ability to record, process, summarize, and report financial data and have identified for Ernst & Young LLP any material weaknesses in internal controls. Moreover, Section 906 of the Sarbanes-Oxley Act of 2002 requires our chief executive officer and chief financial officer to certify that this Quarterly Report on Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in the report fairly presents, in all material respects, our financial condition and results of operations. Before our officers can make such certifications, Ernst & Young LLP must complete its review of the consolidated financial statements appearing elsewhere in this report under AU 722, as required by SEC rules. Once Ernst & Young LLP completes its review under AU 722, we expect to file an amendment to this report in which our chief executive officer and chief financial officer will make the certifications required under Section 302 and Section 906 of the Sarbanes-Oxley Act.

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands, Except Share Amounts)



	June 30, 2014			December 31, 2013
	Not Reviewed
ASSETS
Current assets:
Cash and cash equivalents	$	14,582		$	66,192
Accounts receivable	25,981			35,654
Derivative instruments	395			5,192
Other current assets	8,894			6,756
Total current assets	49,852			113,794
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $8,575,255 and $8,460,589	737,260			753,079
Unproved	49,146			53,645
Net oil and natural gas properties	786,406			806,724
Other property and equipment, net of accumulated depreciation and amortization of $45,265 and $50,058	9,376			11,845
Net property and equipment	795,782			818,569
Deferred income taxes	444			2,230
Goodwill	134,434			134,434
Derivative instruments	363			400
Other assets	15,950			48,525
	$	996,825		$	1,117,952
LIABILITIES AND SHAREHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities	$	129,744		$	141,107
Accrued interest	6,653			6,654
Derivative instruments	13,503			4,542
Deferred income taxes	444			2,230
Other current liabilities	4,864			12,201
Total current liabilities	155,208			166,734
Long-term debt	800,163			800,179
Asset retirement obligations	21,821			22,629
Derivative instruments	1,940			—
Other liabilities	63,332			73,941
Total liabilities	1,042,464			1,063,483
Shareholders’ equity (deficit):
Preferred stock, none issued and outstanding	—			—
Common stock, 119,347,173 and 119,399,983 shares issued and outstanding	11,935			11,940
Capital surplus	2,558,271			2,554,997
Accumulated deficit	(2,605,794		)	(2,502,070		)
Accumulated other comprehensive loss	(10,051		)	(10,398		)
Total shareholders’ equity (deficit)	(45,639		)	54,469
	$	996,825		$	1,117,952

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands, Except Per Share Amounts)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	Not Reviewed						Not Reviewed
Revenues:
Oil, natural gas, and natural gas liquids sales	$	60,106		$	116,786		$	124,563		$	234,828
Interest and other	329			28			1,066			160
Total revenues	60,435			116,814			125,629			234,988
Costs, expenses, and other:
Lease operating expenses	14,295			19,167			28,805			40,371
Production and property taxes	2,740			5,029			5,965			7,245
Transportation and processing costs	2,379			3,098			4,894			6,378
General and administrative	8,260			13,114			16,500			33,128
Depreciation, depletion, and amortization	20,303			43,804			41,718			92,347
Ceiling test write-down of oil and natural gas properties	77,176			—			77,176			—
Interest expense	15,738			29,392			31,749			65,520
Realized and unrealized losses (gains) on derivative instruments, net	11,641			(31,610		)	24,492			(6,030		)
Other, net	(9,302		)	1,593			(654		)	30,413
Total costs, expenses, and other	143,230			83,587			230,645			269,372
Earnings (loss) before income taxes	(82,795		)	33,227			(105,016		)	(34,384		)
Income tax (benefit) expense	(78		)	(212		)	(1,292		)	125
Net earnings (loss)	$	(82,717	)	$	33,439		$	(103,724	)	$	(34,509	)

Basic earnings (loss) per common share	$	(.71	)	$	.28		$	(.89	)	$	(.30	)
Diluted earnings (loss) per common share	$	(.71	)	$	.28		$	(.89	)	$	(.30	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In Thousands)



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014			2013		2014			2013
	Not Reviewed					Not Reviewed
Net earnings (loss)	$	(82,717	)	$	33,439	$	(103,724	)	$	(34,509	)
Other comprehensive income:
Defined benefit postretirement plans - amortization of actuarial losses, net of tax	174			345		347			687
Total other comprehensive income	174			345		347			687

Total comprehensive income (loss)	$	(82,543	)	$	33,784	$	(103,377	)	$	(33,822	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (DEFICIT)

(Unaudited)

(In Thousands)



	Common Stock					Capital Surplus			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity (Deficit)
	Shares		Amount			Capital Surplus			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity (Deficit)
Balances at December 31, 2013	119,400		$	11,940		$	2,554,997		$	(2,502,070	)	$	(10,398	)	$	54,469
	Not Reviewed		Not Reviewed			Not Reviewed			Not Reviewed			Not Reviewed			Not Reviewed
Employee stock purchase plan	74		7			113			—			—			120
Restricted stock issued, net of forfeitures	109		11			(11		)	—			—			—
Amortization of stock-based compensation	—		—			3,824			—			—			3,824
Other, net	(236	)	(23		)	(652		)	—			—			(675		)
Net loss	—		—			—			(103,724		)	—			(103,724		)
Other comprehensive income	—		—			—			—			347			347
Balances at June 30, 2014	119,347		$	11,935		$	2,558,271		$	(2,605,794	)	$	(10,051	)	$	(45,639	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)



	Six Months Ended
	June 30,
	2014			2013
	Not Reviewed
Operating activities:
Net loss	$	(103,724	)	$	(34,509	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	41,718			92,347
Unrealized losses on derivative instruments, net	15,736			15,398
Ceiling test write-down of oil and natural gas properties	77,176			—
Stock-based compensation expense	2,294			6,479
Loss on debt extinguishment	—			25,223
Gain on asset dispositions, net	(21,391		)	—
Other, net	3,034			2,903
Changes in operating assets and liabilities:
Accounts receivable	9,042			(4,168		)
Other current assets	(2,165		)	(269		)
Accounts payable and accrued liabilities	(27,957		)	17,956
Accrued interest and other	19,970			(10,948		)
Net cash provided by operating activities	13,733			110,412
Investing activities:
Capital expenditures for property and equipment:
Exploration, development, and leasehold acquisition costs	(94,786		)	(205,099		)
Other property and equipment	(4,794		)	(1,115		)
Proceeds from sales of assets	24,145			338,977
Net cash (used) provided by investing activities	(75,435		)	132,763
Financing activities:
Proceeds from bank borrowings	—			320,000
Repayments of bank borrowings	—			(255,000		)
Redemption of senior notes	—			(321,327		)
Change in bank overdrafts	11,111			13,523
Other, net	(1,019		)	(1,006		)
Net cash provided (used) by financing activities	10,092			(243,810		)
Net decrease in cash and cash equivalents	(51,610		)	(635		)
Cash and cash equivalents at beginning of period	66,192			1,056
Cash and cash equivalents at end of period	$	14,582		$	421
Cash paid during the period for:
Interest (net of capitalized amounts)	$	29,910		$	70,428
Income taxes (net of refunded amounts)	(21,312		)	1,070
Non-cash investing activities:
Increase (decrease) in accrued capital expenditures	$	1,449		$	(4,259	)

See accompanying Notes to Condensed Consolidated Financial Statements.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) ORGANIZATION AND BASIS OF PRESENTATION

Organization

Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. Forest holds assets in several exploration and producing areas in the United States and has exploratory and development interests in one other country. 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 June 30, 2014, and the results of its operations, its comprehensive income (loss), its cash flows, and changes in its shareholders’ equity (deficit) for the periods presented. Interim results are not necessarily indicative of expected annual results because of various factors including 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.

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”).

Pending Merger

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. This agreement was amended on July 9, 2014 primarily to change the structure of the transaction, in which Forest now will be the surviving entity. The revised transaction structure does not change the economic terms of the transaction. Under the terms of the amended merger agreement, the owners of Sabine will contribute their interests in Sabine to Forest in exchange for Forest common and preferred stock. Upon closing of the combination transaction, Forest’s shareholders will own common shares that represent an approximate 26.5% economic interest in the combined

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company and approximately 20% of the total voting power, and Sabine’s equity holders will own common shares and preferred shares that represent an approximate 73.5% economic interest and approximately 80% of the total voting power in the combined company. Consummation of the transaction is subject to approval by Forest shareholders, regulatory approvals, and other customary closing conditions. The combined entity will change its name to Sabine Oil & Gas Corporation and be headquartered in Houston.

In connection with entering into the amended merger agreement, Forest also adopted a shareholder rights agreement (the “Rights Agreement”), and on July 10, 2014 declared a dividend of one preferred share purchase right (a “Right”) on each outstanding share of Forest’s common stock. This dividend was issued on July 21, 2014. Each Right allows its holder to purchase from Forest one one-hundredth of a share of Series A Junior Participating Preferred Stock for $10, once the Rights become exercisable. This portion of a preferred share will give the shareholder approximately the same dividend and liquidation rights as would one Forest common share. Prior to exercise, the Rights do not give their holders any dividend, voting, or liquidation rights. The Rights will expire on December 31, 2014.

The Rights will not be exercisable until ten days after the public announcement that a person or group has become an “Acquiring Person” by obtaining “beneficial ownership” (as defined in the Rights Agreement) of 5% or more of Forest’s outstanding common shares; provided that a stockholder will not become an “Acquiring Person” if such stockholder certifies to Forest that (i) such stockholder, together with all affiliates and associates of such stockholder, does not and will not at any time prior to December 31, 2014 own or have any beneficial interest in any transaction, security, or derivative or synthetic arrangements having the characteristics of a “short” position in or with respect to any Forest indebtedness or that would increase in value as a result of a decline in the value of any Forest indebtedness or decline in Forest’s credit rating and (ii) such stockholder will continue to satisfy clause (i) for so long as the Rights would otherwise become exercisable.

The Rights Agreement is intended to prevent persons from acquiring beneficial ownership of 5% or more of Forest’s common stock or, for investors that owned in excess of 5% as of July 10, 2014, from increasing their beneficial ownership, but only to the extent such a person has a “short” equivalent position with respect to Forest’s debt. This is to prevent certain hedge funds from rejecting the proposed transaction in order to profit from their short positions in Forest’s debt (and similar derivative positions).

(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.

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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 and six months ended June 30, 2014 and the six months ended June 30, 2013. Unvested restricted stock grants were not included in the calculation of diluted earnings per share for the three months ended June 30, 2013 as their inclusion would have an antidilutive effect.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In Thousands)
Net earnings (loss)	$	(82,717	)	$	33,439		$	(103,724	)	$	(34,509	)
Less: net earnings attributable to participating securities	—			(1,014		)	—			—
Net earnings (loss) for basic and diluted earnings (loss) per share	$	(82,717	)	$	32,425		$	(103,724	)	$	(34,509	)

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



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2014	2013	2014	2013
	(In Thousands)
Weighted average common shares outstanding during the period for basic earnings (loss) per share	117,117	116,033	116,979	115,845
Dilutive effects of potential common shares	—	—	—	—
Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings (loss) per share	117,117	116,033	116,979	115,845

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(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.

Compensation Costs

The table below sets forth stock-based compensation for the three and six months ended June 30, 2014 and 2013, and the remaining unamortized amounts and weighted average amortization period as of June 30, 2014.



	Restricted Stock			Performance Units			Phantom Stock Units			Total⁽¹⁾⁽²⁾
	(In Thousands)
Three Months Ended June 30, 2014:
Total stock-based compensation costs	$	1,605		$	598		$	428		$	2,631
Less: stock-based compensation costs capitalized	(604		)	(122		)	(158		)	(884		)
Stock-based compensation costs expensed	$	1,001		$	476		$	270		$	1,747
Six Months Ended June 30, 2014:
Total stock-based compensation costs	$	3,176		$	600		$	603		$	4,379
Less: stock-based compensation costs capitalized	(1,403		)	(128		)	(272		)	(1,803		)
Stock-based compensation costs expensed	$	1,773		$	472		$	331		$	2,576
Unamortized stock-based compensation costs⁽³⁾	$	5,887		$	2,294		$	2,113		$	10,294
Weighted average amortization period remaining	1.2 years			1.5 years			1.6 years			1.3 years
Three Months Ended June 30, 2013:
Total stock-based compensation costs	$	3,210		$	1,105		$	513		$	4,828
Less: stock-based compensation costs capitalized	(1,172		)	(241		)	(218		)	(1,631		)
Stock-based compensation costs expensed	$	2,038		$	864		$	295		$	3,197
Six Months Ended June 30, 2013:
Total stock-based compensation costs	$	7,445		$	2,733		$	1,775		$	11,953
Less: stock-based compensation costs capitalized	(2,994		)	(714		)	(887		)	(4,595		)
Stock-based compensation costs expensed	$	4,451		$	2,019		$	888		$	7,358

____________________________________________


(1)	Forest also maintains an employee stock purchase plan (which is not included in the table) under which $.02 million and $.1 million of compensation cost was recognized for the three and six months ended June 30, 2014, respectively, and $.1 million and $.2 million of compensation cost was recognized for the three and six months ended June 30, 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.

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Stock Options

The following table summarizes stock option activity in the Plans for the six months ended June 30, 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	(237,100	)	13.86
Outstanding at June 30, 2014	394,106		$	19.23	$	—	394,106

____________________________________________


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

Restricted Stock, Performance Units, and Phantom Stock Units

The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Plans for the six months ended June 30, 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	407,202		2.22				—		—				67,000		3.51
Vested	(905,882	)	14.41		$	2,455	(63,840	)	18.11		$	—	(343,583	)	7.07		$	1,127
Forfeited	(297,954	)	10.29				(170,300	)	9.33				(184,139	)	7.54
Unvested at June 30, 2014	1,993,908		$	6.69			1,277,000		$	7.89			1,464,097		$	6.43

____________________________________________


(1)	Of the unvested restricted stock as of June 30, 2014, 436,956 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 June 30, 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 June 30, 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 six months ended June 30, 2014 were settled in cash. Of the unvested phantom stock units as of June 30, 2014, (i) 122,509 were granted in 2011 and 466,588 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, and (iii) 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.

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(4) DEBT

The components of debt are as follows:



	June 30, 2014						December 31, 2013
	Principal		Unamortized Premium		Total		Principal		Unamortized Premium		Total
	(In Thousands)
Credit facility	$	—	$	—	$	—	$	—	$	—	$	—
7¼% senior notes due 2019	577,914		162		578,076		577,914		178		578,092
7½% senior notes due 2020	222,087		—		222,087		222,087		—		222,087
Total long-term debt	$	800,001	$	162	$	800,163	$	800,001	$	178	$	800,179

Bank Credit Facility

As of June 30, 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, where it remained as of June 30, 2014.

The determination of the Credit Facility 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 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.

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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. 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 June 30, 2014, as calculated in accordance with the Credit Facility, was 5.07.

Based on Forest’s current projections, the ratio of total debt to EBITDA may exceed the maximum allowed under the Credit Facility sometime prior to the end of 2014 if it does not obtain a waiver or an additional amendment to the Credit Facility. Forest believes that it will be able to obtain such a waiver or an amendment prior to the ratio exceeding the maximum amount currently allowed. If Forest fails to obtain a waiver or an amendment, the Credit Facility could be terminated. However, Forest believes it can obtain alternative sources of debt financing sufficient for its needs, including securing liens against its properties or selling additional properties.

At June 30, 2014, there were no outstanding borrowings under the Credit Facility and Forest had used the Credit Facility for $2.2 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 natural 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 natural 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 June 30, 2014 and 2013, Forest capitalized $4.9 million and $8.1 million, respectively, of general and administrative costs (including stock-based compensation). During the six months ended June 30, 2014 and 2013, Forest capitalized $9.4 million and $20.4 million, respectively, of general and administrative costs (including stock-based compensation). During the three and six months ended June 30, 2013, Forest capitalized $.9 million and $1.1 million of interest costs attributed to significant unproved acreage positions under development. No interest costs were capitalized during the three and six months ended June 30, 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 factors such as the primary lease terms of the properties, the holding period of the properties, geographic and geologic data obtained relating to the properties, market acreage prices, and estimated discounted future net cash flows from the properties. Estimated discounted future net cash flows are based on discounted future net revenues associated with probable and possible reserves, risk adjusted as appropriate. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.

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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 natural 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 natural 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.

At June 30, 2014, Forest recorded a $77.2 million ceiling test write-down of its United States cost center. This ceiling test write-down was primarily a result of (i) a reduction in the estimated reserves attributable to a portion of Forest’s proved undeveloped locations in the Eagle Ford and (ii) a reduction in the total number of proved undeveloped locations in the Eagle Ford to properly align the number of future drilling locations with Forest’s current development pace relative to the SEC five year limitation on the age of proved undeveloped locations. Additional ceiling test write-downs 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 June 30, 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.

Gain or loss is not recognized on the sale of oil and natural gas properties unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and natural gas reserves attributable to a cost center. A significant alteration would not ordinarily be expected to occur for sales involving less than 25% of the reserve quantities of a given cost center.

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

Divestitures

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 proceeds of $985.3 million through June 2014, with the purchase price having been adjusted to, among other things, reflect an economic effective date of October 1, 2013. The proceeds received include $20.2 million that Forest received in May 2014 from the final settlement of the escrow account that had been established for this transaction. Forest used a portion of the Panhandle divestiture proceeds to repay the balance outstanding at the time of the closing 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 November 2013.

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In connection with the Panhandle divestiture, Forest incurred exit costs consisting of $4.7 million of one-time employee termination benefits and $8.1 million of other associated costs. No further significant exit costs are expected to be incurred for this divestiture. A reconciliation of the beginning and ending liability balances for these exit costs for the six months ended June 30, 2014 is set forth in the table below.



	One-Time Employee Termination Benefits			Other Associated Costs⁽¹⁾			Total
	(In Thousands)
Liability balance as of December 31, 2013	$	1,095		$	5,840		$	6,935
Costs incurred⁽²⁾	687			116			803
Costs paid	(1,782		)	(5,840		)	(7,622		)
Liability balance as of June 30, 2014⁽³⁾	$	—		$	116		$	116

____________________________________________


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

(2)

Of the $.8 million costs incurred during the six months ended June 30, 2014, (i) $.7 million was recognized as an expense in “General and administrative” expense, $.5 million during the quarter ended March 31, 2014 and $.1 million during the quarter ended June 30, 2014, and (ii) $.1 million was recognized as an expense in “Other, net” during the quarter ended June 30, 2014. During the year ended December 31, 2013, $12.0 million of costs were incurred, with (i) $5.0 million recognized as an expense in “General and administrative” expense, (ii) $5.8 million recognized as an expense in “Other, net”, and (iii) $1.1 million capitalized in “Oil and natural gas properties” pursuant to the full cost method of accounting.


(3)	The June 30, 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 third quarter of 2014.

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. Net gains of $19.0 million and $18.2 million were recognized on the divestiture for the three and six months ended June 30, 2014, respectively, as customary post-closing purchase price adjustments were made and additional proceeds were received. These gains are included in “Other, net” in the Condensed Consolidated Statements of Operations.

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 oil properties, for $325.0 million in cash. This transaction closed on February 15, 2013, and Forest has received 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 six months ended June 30, 2013 and were paid in full during 2013.

South Africa

In December 2012, Forest entered into an agreement with a third-party to sell its South African subsidiary which holds a production right related to Block 2A in South Africa. Following approval of the sale by the government of South Africa, the sale closed and Forest received a payment of $1.0 million during the three months ended June 30, 2014. This sale completes Forest’s exit from South Africa, though certain regulatory matters are delaying transfer of physical possession of the subsidiary’s shares to the purchaser. As a result of this closing, Forest recorded a net gain of $3.2 million in other income within the “Other, net” line item in the Condensed Consolidated Statement of Operations. Forest may receive future payments depending on the purchaser’s success in obtaining natural gas sales contracts and commencing development operations.

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Acquisition and Development Agreement

In April 2013, Forest entered into an Acquisition and Development Agreement (“ADA”) with a third-party for the future development of Forest’s Eagle Ford acreage in Gonzales County, Texas. Under the terms of the ADA, the third-party will pay a $90.0 million drilling carry in the form of future drilling and completion services and related development capital in exchange for a 50% working interest in Forest’s Eagle Ford acreage position. Upon completion of the phased contribution of the drilling carry, Forest and the third-party will participate in future drilling on a 50/50 basis. The ADA applies to wells spud on or subsequent to November 28, 2012, none of which had been placed on production prior to April 1, 2013, and Forest retained all of its interests in wells that were spud prior to November 28, 2012 and production from those wells. Forest is the operator of the drilling program. As of June 30, 2014, Forest had realized $70.4 million of the drilling carry.

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 natural 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 .1% and 1.2% for the three and six months ended June 30, 2014, respectively, and (.6)% and (.4)% for the three and six months ended June 30, 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. 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, and during the three months ended June 30, 2014, Forest received a refund of $15.8 million, including interest income of $.3 million, for a total refund received during the six months ended June 30, 2014 of $22.3 million, including $1.0 million of interest income. Credits to current income tax expense of $.6 million and $.1 million were recorded for the three months ended March 31, 2014 and June 30, 2014, respectively, as a result of these refunds.

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(7) FAIR VALUE MEASUREMENTS

Forest’s assets and liabilities measured at fair value on a recurring basis at June 30, 2014 and December 31, 2013 are set forth in the table below.



	June 30, 2014		December 31, 2013
	Using Significant Other Observable Inputs (Level 2)⁽¹⁾
	(In Thousands)
Assets:
Derivative instruments⁽²⁾:
Commodity	$	758	$	5,592
Liabilities:
Derivative instruments⁽²⁾:
Commodity	$	15,443	$	4,542

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(1)

The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when relevant observable inputs are not available. There were no transfers between levels of the fair value hierarchy during the three and six months ended June 30, 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.



	June 30, 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	$	758	$	758	$	—	$	758
Liabilities:
Derivative instruments	15,443		15,443		—		15,443
7¼% senior notes due 2019	578,076		572,499		572,499		—
7½% senior notes due 2020	222,087		221,116		221,116		—

__________________________________________


(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.

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	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 (gains) on derivative instruments, net” in the Condensed Consolidated Statement of Operations.

The table below sets forth Forest’s outstanding commodity swaps as of June 30, 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
July 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 June 30, 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

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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 June 30, 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
Natural 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.



	June 30, 2014		December 31, 2013
	(In Thousands)
Current assets:
Derivative instruments:
Commodity	$	395	$	5,192
Long-term assets:
Derivative instruments:
Commodity	$	363	$	400
Current liabilities:
Derivative instruments:
Commodity	$	13,503	$	4,542
Long-term liabilities:
Derivative instruments:
Commodity	$	1,940	$	—

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



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014		2013			2014		2013
	(In Thousands)
Commodity derivatives:
Realized losses (gains)	$	4,296	$	1,106		$	8,756	$	(8,543	)
Unrealized losses (gains)	7,345		(32,823		)	15,736		2,338
Interest rate derivatives:
Realized gains	—		(9,803		)	—		(12,885		)
Unrealized losses	—		9,910			—		13,060
Realized and unrealized losses (gains) on derivative instruments, net	$	11,641	$	(31,610	)	$	24,492	$	(6,030	)

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 June 30, 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

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of collateral for its benefit under its derivative agreements. However, the ISDA Master Agreements and Schedules generally contain netting provisions whereby if on any date amounts would otherwise be payable by each party to the other, then on such date, the party that owes the larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party’s obligations. These provisions generally apply to all derivative transactions, or all derivative transactions of the same type (e.g., commodity, interest rate, etc.), with the particular counterparty. If all counterparties failed, Forest would be exposed to a risk of loss equal to this net amount owed to Forest, the fair value of which was $.1 million at June 30, 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 June 30, 2014, Forest owed a net derivative liability to its counterparties, the fair value of which was $14.8 million. In the absence of netting provisions, at June 30, 2014, Forest would be exposed to a risk of loss of $.8 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $15.4 million.

For financial reporting purposes, Forest has elected not to 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
	June 30, 2014			December 31, 2013
	(In Thousands)
Gross amounts of recognized assets	$	758		$	5,592
Gross amounts offset in the balance sheet	—			—
Net amounts of assets presented in the balance sheet	758			5,592
Gross amounts not offset in the balance sheet:
Derivative instruments	(641		)	(1,049		)
Cash collateral received	—			—
Net amount	$	117		$	4,543



	Derivative Liabilities
	June 30, 2014			December 31, 2013
	(In Thousands)
Gross amounts of recognized liabilities	$	15,443		$	4,542
Gross amounts offset in the balance sheet	—			—
Net amounts of liabilities presented in the balance sheet	15,443			4,542
Gross amounts not offset in the balance sheet:
Derivative instruments	(641		)	(1,049		)
Cash collateral pledged	—			—
Net amount	$	14,802		$	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.

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(9) COSTS, EXPENSES, AND OTHER

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In Thousands)
Accretion of asset retirement obligations	$	381		$	549		$	894		$	1,793
Write-off of debt issuance costs	—			—			3,323			—
Loss on debt extinguishment	—			—			—			25,223
Gain on asset dispositions, net	(22,185		)	—			(21,391		)	—
Merger-related costs	10,202			—			10,202			—
Rig stacking/lease termination	3,075			1,258			8,259			4,296
Other, net	(775		)	(214		)	(1,941		)	(899		)
	$	(9,302	)	$	1,593		$	(654	)	$	30,413

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 debt issuance costs and discount.

Gain on Asset Dispositions, 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 divestiture closed in November 2013 and Forest has received proceeds of $985.3 million through June 2014, after customary purchase price adjustments. Net gains of $19.0 million and $18.2 million were recognized on the divestiture for the three and six months ended June 30, 2014, respectively, as customary post-closing purchase price adjustments were made and additional proceeds were received, including the $20.2 million received in May 2014. Also included in the gain on asset disposition line item is a $3.2 million gain recognized on the sale of Forest’s South African subsidiary. See Note 5 for more information on these divestitures.

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Merger-Related Costs

In connection with the pending merger with Sabine, Forest has incurred expenses that are comprised primarily of legal and financial advisor costs. See Note 1 for more information on the pending merger.

Rig Stacking/Lease Termination

Rig stacking comprises the expenses incurred to operate and maintain drilling rigs, which Forest has historically leased under operating leases, that were not being utilized on capital projects. Rig stacking expenses for the three and six months ended June 30, 2014 were $1.6 million and $4.4 million, respectively. Rig stacking expenses for the three and six months ended June 30, 2013 were $1.3 million and $4.3 million, respectively.

During the three months ended March 31, 2014, Forest terminated the operating leases on seven drilling rigs and during the three months ended June 30, 2014, Forest terminated the operating leases on two additional drilling rigs. In connection with these lease terminations, Forest recognized expense of $1.4 million and $3.9 million during the three and six months ended June 30, 2014, respectively.

As of June 30, 2014, Forest has six rigs remaining under non-cancelable operating leases which are scheduled to terminate in September 2014. Lease payments under the remaining operating leases are $.4 million per month.

(10) COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that, under generally accepted accounting principles, are reported as separate components of shareholders’ equity instead of net earnings (loss). Forest’s other comprehensive income during the three and six months ended June 30, 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 and six months ended June 30, 2014 are as follows:



	Before-Tax		Tax (Expense) / Benefit⁽¹⁾		Net-of-Tax
	(In Thousands)
Three Months Ended June 30, 2014:
Defined benefit postretirement plans
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost	$	174	$	—	$	174
Other comprehensive income	$	174	$	—	$	174
Six Months Ended June 30, 2014:
Defined benefit postretirement plans
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost	$	347	$	—	$	347
Other comprehensive income	$	347	$	—	$	347

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

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The change in the accumulated balance of other comprehensive loss during the six months ended June 30, 2014 is as follows:



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

Amounts reclassified from accumulated other comprehensive loss	347
Other comprehensive income	347

Balance at June 30, 2014	$	(10,051	)

____________________________________


(1)	All amounts are net of tax.

(11) RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 is the result of a joint project with the International Accounting Standards Board intended to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. generally accepted accounting principles and International Financial Reporting Standards. The guidance is expected to enhance comparability of revenue recognition practices across entities, industries, jurisdictions, and capital markets. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. Entities must adopt ASU 2014-09 using either a full retrospective approach or a modified retrospective approach with a cumulative effect of adoption recognized in the opening balance of retained earnings at the date of adoption. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. Forest has not yet determined the effect that adoption of ASU 2014-09 will have on its financial statements, nor has Forest determined which transition method it will use upon adoption.

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.

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

OVERVIEW

All expectations, forecasts, assumptions, and beliefs about our future financial results, condition, operations, strategic plans, and performance are forward-looking statements, as described in more detail under the heading “Forward-Looking Statements” below. Our actual results may differ materially because of a number of risks and uncertainties. Historical statements made herein are accurate only as of the date of filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”), and may be relied upon only as of that date. The following discussion and analysis should be read in conjunction with Forest’s Condensed Consolidated Financial Statements and the Notes thereto, the information included or incorporated by reference under the headings “Forward-Looking Statements” and “Risk Factors” below, and the information included or incorporated by reference in Forest’s 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

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. This agreement was amended on July 9, 2014 primarily to change the structure of the transaction, in which Forest now will be the surviving entity. The revised transaction structure does not change the economic terms of the transaction. Under the terms of the amended merger agreement, the owners of Sabine will contribute their interests in Sabine to Forest, in exchange for Forest common and preferred stock. Upon closing of the combination transaction, Forest’s shareholders will own common shares that represent an approximate 26.5% economic interest in the combined company and approximately 20% of the total voting power, and Sabine’s equity holders will own common shares and preferred shares that represent an approximate 73.5% economic interest and approximately 80% of the total voting power in the combined company. Consummation of the transaction is subject to approval by Forest shareholders, regulatory approvals, and other customary closing conditions. The combined entity will change its name to Sabine Oil & Gas Corporation and be headquartered in Houston.

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 proceeds of $985 million through June 2014, including $20 million received in May 2014, after customary purchase price adjustments and escrow account settlements. 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 received 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 and six months ended June 30, 2014 and the three and six months ended June 30, 2013 presented herein.

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RESULTS OF OPERATIONS

For the three and six months ended June 30, 2014, we recognized net losses of $83 million and $104 million, respectively, compared to net earnings of $33 million and a net loss of $35 million for the three and six months ended June 30, 2013, respectively. Adjusted EBITDA, which is a measure used by management, securities analysts, and investors that consists of net earnings (loss) before interest expense, income taxes, depreciation, depletion, and amortization, as well as other items including ceiling test write-downs and unrealized gains and losses on derivative instruments, was $31 million and $66 million for the three and six months ended June 30, 2014, respectively, compared to $88 million and $182 million for the three and six months ended June 30, 2013, respectively. The decreases in EBITDA in the 2014 periods as compared to the 2013 periods were 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 earnings (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 and year-to-date results follows.

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

Oil, natural gas, and natural gas liquids sales volumes, revenues, and per unit price realizations for the three and six months ended June 30, 2014 and 2013 are set forth in the table below.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Sales volumes:
Oil (MBbls)	292		601		618		1,160
Natural gas (MMcf)	6,216		11,406		12,654		25,738
NGLs (MBbls)	182		694		360		1,392
Totals (MMcfe)	9,060		19,176		18,522		41,050
Revenues (in thousands):
Oil	$	28,107	$	56,316	$	58,439	$	110,278
Natural gas	26,545		41,161		54,716		83,819
NGLs	5,454		19,309		11,408		40,731
Totals	$	60,106	$	116,786	$	124,563	$	234,828
Per unit price realizations:
Oil ($/Bbl)	$	96.26	$	93.70	$	94.56	$	95.07
Natural gas ($/Mcf)	4.27		3.61		4.32		3.26
NGLs ($/Bbl)	29.97		27.82		31.69		29.26
Totals ($/Mcfe)	$	6.63	$	6.09	$	6.73	$	5.72

We have divested a substantial amount of oil and natural gas properties in recent years, causing significant changes from period to period in our oil, natural gas, and NGL revenues and sales volumes and causing historical amounts reported to be not necessarily indicative of future results. Accordingly, the tables below distinguish oil, natural gas, and NGL sales revenues and volumes, as well as per unit price realizations, between those oil and natural gas properties that we have recently divested, i.e., South Texas and Texas Panhandle properties (the “Divested properties”) and those oil and natural gas properties that we continued to own as of June 30, 2014 (the “Retained properties”).

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	Oil, Natural Gas, and NGL Revenues							Oil, Natural Gas, and NGL Sales Volumes				Per Unit Price Realizations							Change In Revenues Attributable to Change In:
	Three Months Ended June 30,				$ Change			Three Months Ended June 30,		Volume Change		Three Months Ended June 30,				$ Change			Volumes (1)			Prices (2)			Total
	2014		2013		$ Change			2014	2013	Volume Change		2014		2013		$ Change			Volumes (1)			Prices (2)			Total
	(In Thousands)																		(In Thousands)
Oil								MBbls				$/Bbl
Retained properties	$	28,107	$	28,545	$	(438	)	292	285	7		$	96.26	$	100.16	$	(3.90	)	$	701		$	(1,139	)	$	(438	)
Divested properties	—		27,771		(27,771		)	—	316	(316	)	—		87.88		(87.88		)	(27,771		)	—			(27,771		)
	$	28,107	$	56,316	$	(28,209	)	292	601	(309	)	$	96.26	$	93.70	$	2.55		$	(28,954	)	$	745		$	(28,209	)

Natural gas								MMcf				$/Mcf
Retained properties	$	26,545	$	26,998	$	(453	)	6,216	7,146	(930	)	$	4.27	$	3.78	$	.49		$	(3,514	)	$	3,061		$	(453	)
Divested properties	—		14,163		(14,163		)	—	4,260	(4,260	)	—		3.32		(3.32		)	(14,163		)	—			(14,163		)
	$	26,545	$	41,161	$	(14,616	)	6,216	11,406	(5,190	)	$	4.27	$	3.61	$	.66		$	(18,729	)	$	4,113		$	(14,616	)

NGLs								MBbls				$/Bbl
Retained properties	$	5,454	$	5,066	$	388		182	180	2		$	29.97	$	28.14	$	1.82		$	56		$	332		$	388
Divested properties	—		14,243		(14,243		)	—	514	(514	)	—		27.71		(27.71		)	(14,243		)	—			(14,243		)
	$	5,454	$	19,309	$	(13,855	)	182	694	(512	)	$	29.97	$	27.82	$	2.14		$	(14,245	)	$	390		$	(13,855	)

Total								MMcfe				$/Mcfe
Retained properties	$	60,106	$	60,609	$	(503	)	9,060	9,936	(876	)	$	6.63	$	6.10	$	.53		$	(5,344	)	$	4,841		$	(503	)
Divested properties	—		56,177		(56,177		)	—	9,240	(9,240	)	—		6.08		(6.08		)	(56,177		)	—			(56,177		)
	$	60,106	$	116,786	$	(56,680	)	9,060	19,176	(10,116	)	$	6.63	$	6.09	$	.54		$	(61,609	)	$	4,929		$	(56,680	)

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(1)	The change in revenues attributable to the change in volumes is calculated as the product of (i) the per unit price realization for the three months ended June 30, 2013 and (ii) the change in volumes between the three months ended June 30, 2013 and the three months ended June 30, 2014. Certain amounts do not foot due to rounding.


(2)	The change in revenues attributable to the change in prices is calculated as the product of (i) the volumes for the three months ended June 30, 2014 and (ii) the change in the per unit price realization between the three months ended June 30, 2013 and the three months ended June 30, 2014. Certain amounts do not foot due to rounding.

Equivalent sales volumes were 9.1 Bcfe for the three months ended June 30, 2014 as compared to 19.2 Bcfe for the three months ended June 30, 2013. The 10.1 Bcfe, or 53%, decrease in equivalent sales volumes for the three months ended June 30, 2014 compared to the three months ended June 30, 2013 was primarily due to the divestitures of producing oil and natural gas properties in the Texas Panhandle, which accounted for 9.2 Bcfe of the decrease. Equivalent sales volumes attributable to properties we continued to own as of June 30, 2014 decreased 9% to 9.1 Bcfe for the three months ended June 30, 2014 from 9.9 Bcfe for the three months ended June 30, 2013. The 9% decrease in these equivalent sales volumes was due to a 13% decrease in natural gas production partially offset by a 2% increase in oil production and a 1% increase in NGL production. The increase in oil production was a result of our development efforts in the Eagle Ford, where we incurred approximately $16 million in direct exploration, development, and leasehold acquisition capital expenditures during the three months ended June 30, 2014 and the increase in NGL production was due to our drilling program in East Texas, where we incurred approximately $34

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million in direct exploration, development, and leasehold acquisition capital expenditures during the three months ended June 30, 2014. Natural gas production declined 13% due to the natural decline in production from existing wells that exceeded the incremental natural gas production we added during the three months ended June 30, 2014 from drilling liquids-rich East Texas wells.

Revenues from oil, natural gas, and NGLs were $60 million in the second quarter of 2014 as compared to $117 million in the second quarter of 2013. The $57 million, or 49%, decrease in revenues in the second quarter of 2014 compared to the second quarter of 2013 was primarily due to the divestitures of producing oil and natural gas properties in the Texas Panhandle, which accounted for $56 million of the decrease. Revenues from the properties we continued to own as of June 30, 2014 decreased by $1 million primarily due to decreased natural gas production and per unit price realizations for oil, partially offset by increased natural gas and NGL per unit price realizations and oil production between the two periods.



	Oil, Natural Gas, and NGL Revenues							Oil, Natural Gas, and NGL Sales Volumes				Per Unit Price Realizations							Change In Revenues Attributable to Change In:
	Six Months Ended June 30,				$ Change			Six Months Ended June 30,		Volume Change		Six Months Ended June 30,				$ Change			Volumes (1)			Prices (2)			Total
	2014		2013		$ Change			2014	2013	Volume Change		2014		2013		$ Change			Volumes (1)			Prices (2)			Total
	(In Thousands)																		(In Thousands)
Oil								MBbls				$/Bbl
Retained properties	$	58,439	$	55,770	$	2,669		618	547	71		$	94.56	$	101.96	$	(7.39	)	$	7,239		$	(4,570	)	$	2,669
Divested properties	—		54,508		(54,508		)	—	613	(613	)	—		88.92		(88.92		)	(54,508		)	—			(54,508		)
	$	58,439	$	110,278	$	(51,839	)	618	1,160	(542	)	$	94.56	$	95.07	$	(.51	)	$	(51,526	)	$	(313	)	$	(51,839	)

Natural gas								MMcf				$/Mcf
Retained properties	$	54,716	$	50,886	$	3,830		12,654	14,812	(2,158	)	$	4.32	$	3.44	$	.89		$	(7,414	)	$	11,244		$	3,830
Divested properties	—		32,933		(32,933		)	—	10,926	(10,926	)	—		3.01		(3.01		)	(32,933		)	—			(32,933		)
	$	54,716	$	83,819	$	(29,103	)	12,654	25,738	(13,084	)	$	4.32	$	3.26	$	1.07		$	(42,610	)	$	13,507		$	(29,103	)

NGLs								MBbls				$/Bbl
Retained properties	$	11,408	$	10,665	$	743		360	354	6		$	31.69	$	30.13	$	1.56		$	181		$	562		$	743
Divested properties	—		30,066		(30,066		)	—	1,038	(1,038	)	—		28.97		(28.97		)	(30,066		)	—			(30,066		)
	$	11,408	$	40,731	$	(29,323	)	360	1,392	(1,032	)	$	31.69	$	29.26	$	2.43		$	(30,197	)	$	874		$	(29,323	)

Total								MMcfe				$/Mcfe
Retained properties	$	124,563	$	117,321	$	7,242		18,522	20,218	(1,696	)	$	6.73	$	5.80	$	.92		$	(9,842	)	$	17,084		$	7,242
Divested properties	—		117,507		(117,507		)	—	20,832	(20,832	)	—		5.64		(5.64		)	(117,507		)	—			(117,507		)
	$	124,563	$	234,828	$	(110,265	)	18,522	41,050	(22,528	)	$	6.73	$	5.72	$	1.00		$	(128,872	)	$	18,607		$	(110,265	)

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(1)	The change in revenues attributable to the change in volumes is calculated as the product of (i) the per unit price realization for the six months ended June 30, 2013 and (ii) the change in volumes between the six months ended June 30, 2013 and the six months ended June 30, 2014. Certain amounts do not foot due to rounding.

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(2)	The change in revenues attributable to the change in prices is calculated as the product of (i) the volumes for the six months ended June 30, 2014 and (ii) the change in the per unit price realization between the six months ended June 30, 2013 and the six months ended June 30, 2014. Certain amounts do not foot due to rounding.

Equivalent sales volumes were 18.5 Bcfe for the six months ended June 30, 2014 compared to 41.1 Bcfe for the six months ended June 30, 2013. The 22.5 Bcfe, or 55%, decrease in equivalent sales volumes for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 was primarily due to the divestitures of producing oil and natural gas properties in South Texas and the Texas Panhandle, which accounted for 20.8 Bcfe of the decrease. Equivalent sales volumes attributable to properties we continued to own as of June 30, 2014 decreased 8% to 18.5 Bcfe for the six months ended June 30, 2014 from 20.2 Bcfe for the six months ended June 30, 2013. The 8% decrease in these equivalent sales volumes was due to a 15% decrease in natural gas production partially offset by a 13% increase in oil production and a 2% increase in NGL production. The increase in oil production was a result of our development efforts in the Eagle Ford, where we incurred approximately $38 million in direct exploration, development, and leasehold acquisition capital expenditures in the six months ended June 30, 2014 and the increase in NGL production was due to our drilling program in East Texas, where we incurred approximately $57 million in direct exploration, development, and leasehold acquisition capital expenditures in the six months ended June 30, 2014. Natural gas production declined 15% due to the natural decline in production from existing wells that exceeded the incremental natural gas production we added during the six months ended June 30, 2014 from drilling liquids-rich East Texas wells.

Revenues from oil, natural gas, and NGLs were $125 million in the first six months of 2014 compared to $235 million in the first six months of 2013. The $110 million, or 47%, decrease in the first six months of 2014 compared to the first six months of 2013 was primarily due to the divestitures of producing oil and natural gas properties in South Texas and the Texas Panhandle, which accounted for $118 million of the decrease. Revenues from the properties we continued to own as of June 30, 2014 increased by $7 million, primarily due to increased natural gas and NGL per unit price realizations and oil and NGL production, partially offset by decreased natural gas production and oil per unit price realizations between the two periods.

The revenues and per unit price realizations reflected in the tables 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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In Thousands, Except Per Mcfe Data)
Production expense:
Lease operating expenses	$	14,295	$	19,167	$	28,805	$	40,371
Production and property taxes	2,740		5,029		5,965		7,245
Transportation and processing costs	2,379		3,098		4,894		6,378
Production expense	$	19,414	$	27,294	$	39,664	$	53,994
Production expense per Mcfe:
Lease operating expenses	$	1.58	$	1.00	$	1.56	$	.98
Production and property taxes	.30		.26		.32		.18
Transportation and processing costs	.26		.16		.26		.16
Production expense per Mcfe	$	2.14	$	1.42	$	2.14	$	1.32

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We have divested a substantial amount of oil and natural gas properties in recent years, causing significant changes from period to period in our lease operating expenses, production and property taxes, and transportation and processing costs and causing historical amounts reported to be not necessarily indicative of future results. Accordingly, the tables below distinguish lease operating expenses, production and property taxes, and transportation and processing costs, as well as per unit production expense, between those oil and natural gas properties we have recently divested, i.e., the South Texas and Texas Panhandle properties (the “Divested properties”) and those oil and natural gas properties that we continued to own as of June 30, 2014 (the “Retained properties”).



	Production Expense							Production Expense per Mcfe
	Three Months Ended June 30,				$ Change			Three Months Ended June 30,				$ Change
	2014		2013		$ Change			2014		2013		$ Change
Lease operating expenses	(In Thousands)							$/Mcfe
Retained properties	$	14,295	$	12,433	$	1,862		$	1.58	$	1.25	$	.33
Divested properties	—		6,734		(6,734		)	—		.73		(.73		)
	$	14,295	$	19,167	$	(4,872	)	$	1.58	$	1.00	$	.58
Production and property taxes
Retained properties	$	2,740	$	2,139	$	601		$	.30	$	.22	$	.08
Divested properties	—		2,890		(2,890		)	—		.31		(.31		)
	$	2,740	$	5,029	$	(2,289	)	$	.30	$	.26	$	.04
Transportation and processing costs
Retained properties	$	2,379	$	3,013	$	(634	)	$	.26	$	.30	$	(.04	)
Divested properties	—		85		(85		)	—		.01		(.01		)
	$	2,379	$	3,098	$	(719	)	$	.26	$	.16	$	.10
Total
Retained properties	$	19,414	$	17,585	$	1,829		$	2.14	$	1.77	$	.37
Divested properties	—		9,709		(9,709		)	—		1.05		(1.05		)
	$	19,414	$	27,294	$	(7,880	)	$	2.14	$	1.42	$	.72

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	Production Expense							Production Expense per Mcfe
	Six Months Ended June 30,				$ Change			Six Months Ended June 30,				$ Change
	2014		2013		$ Change			2014		2013		$ Change
Lease operating expenses	(In Thousands)							$/Mcfe
Retained properties	$	28,805	$	23,121	$	5,684		$	1.56	$	1.14	$	.42
Divested properties	—		17,250		(17,250		)	—		.83		(.83		)
	$	28,805	$	40,371	$	(11,566	)	$	1.56	$	.98	$	.58
Production and property taxes
Retained properties	$	5,965	$	4,665	$	1,300		$	.32	$	.23	$	.09
Divested properties	—		2,580		(2,580		)	—		.12		(.12		)
	$	5,965	$	7,245	$	(1,280	)	$	.32	$	.18	$	.14
Transportation and processing costs
Retained properties	$	4,894	$	6,033	$	(1,139	)	$	.26	$	.30	$	(.04	)
Divested properties	—		345		(345		)	—		.02		(.02		)
	$	4,894	$	6,378	$	(1,484	)	$	.26	$	.16	$	.10
Total
Retained properties	$	39,664	$	33,819	$	5,845		$	2.14	$	1.67	$	.47
Divested properties	—		20,175		(20,175		)	—		.97		(.97		)
	$	39,664	$	53,994	$	(14,330	)	$	2.14	$	1.32	$	.82

Lease Operating Expenses

Lease operating expenses in the second quarter of 2014 were $14 million, or $1.58 per Mcfe, compared to $19 million, or $1.00 per Mcfe, in the second quarter of 2013. Lease operating expenses in the first six months of 2014 were $29 million, or $1.56 per Mcfe, compared to $40 million, or $.98 per Mcfe, in the first six months of 2013. Lease operating expenses decreased $5 million in the second quarter of 2014 compared to the second quarter of 2013 and $12 million in the first six months of 2014 as compared to the first six months of 2013. The decreases in lease operating expenses were primarily the result of oil and natural gas property divestitures, as reflected in the tables above, offset by increases in the lease operating expenses associated with properties we continued to own as of June 30, 2014, which increased by $2 million and $6 million during the second quarter of 2014 and the first six months of 2014, respectively, as compared to the comparable prior year periods. The $2 million increase in the second quarter of 2014 was primarily due to a $1 million increase in chemical treatment costs related to our oil production and a $1 million increase in workover expense. The $6 million increase in the first six months of 2014 was primarily due to increases in chemical treatment and saltwater disposal costs related to our oil production of $2 million and $1 million, respectively, and an increase in workover expense of $1 million.

Production and Property Taxes

Production and property taxes, consisting primarily of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 4.6% and 4.3% of oil, natural gas, and NGL revenues for the three months ended June 30, 2014 and 2013, respectively, and 4.8% and 3.1% of oil, natural gas, and NGL revenues for the six months ended June 30, 2014 and 2013, respectively. During the second quarter of 2013, several of our North Louisiana wells became eligible for horizontal well tax incentives and during the first quarter of 2013, reduced severance tax rates were approved on several wells in the Texas Panhandle. At the time of eligibility or approval, refunds were accrued to recover the severance taxes paid on these wells prior to them becoming eligible or approved for reduced rates, causing a decrease in production taxes of $1 million and $4 million during the three and six months ended June 30, 2013, respectively, and therefore causing the production and property taxes as a percentage of revenues to be lower for those periods. Excluding the production and property taxes and revenues related to the divested South Texas and

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Texas Panhandle properties, production and property taxes were 3.5% and 4.0% of oil, natural gas, and NGL revenues for the three and six months ended June 30, 2013, respectively. Normal fluctuations occur in this percentage between periods based upon changes in tax rates and changes in the assessed values of oil and natural gas properties and equipment for purposes of ad valorem taxes.

Transportation and Processing Costs

Transportation and processing costs in the second quarter of 2014 were $2 million, or $.26 per Mcfe, compared to $3 million, or $.16 per Mcfe, in the second quarter of 2013. Transportation and processing costs in the first six months of 2014 were $5 million, or $.26 per Mcfe, compared to $6 million, or $.16 per Mcfe, in the first six months of 2013. The divested South Texas and Texas Panhandle properties had minimal transportation and processing costs associated with them, and as a result these divestitures had a lesser impact in reducing transportation and processing costs.

General and Administrative Expense

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In Thousands)
Stock-based compensation costs	$	2,653		$	4,881		$	4,427		$	12,105
Stock-based compensation costs capitalized	(884		)	(1,631		)	(1,803		)	(4,595		)
	1,769			3,250			2,624			7,510

Labor costs⁽¹⁾	5,879			10,873			12,095			30,769
Other general and administrative costs	4,579			5,458			9,387			10,650
General and administrative costs capitalized	(3,967		)	(6,467		)	(7,606		)	(15,801		)
	6,491			9,864			13,876			25,618

General and administrative expense	$	8,260		$	13,114		$	16,500		$	33,128

____________________________________________


(1)	Labor costs include salaries, hourly wages, bonuses, severance, and burden.

General and administrative expense was $8 million in the second quarter of 2014 compared to $13 million in the second quarter of 2013, and was $17 million in the first six months of 2014 compared to $33 million in the first six months of 2013. The primary factors causing the decreases in general and administrative expense between the comparative quarterly and year-to-date periods are the South Texas and Texas Panhandle oil and natural gas property divestitures that occurred in February 2013 and November 2013, respectively, each of which included a reduction in employee headcount.

Labor costs decreased $5 million, or 46%, in the second quarter of 2014 as compared to the second quarter of 2013, and $19 million, or 61%, in the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. The six months ended June 30, 2013 included $8 million of employee-related South Texas asset divestiture costs comprised of severance paid to involuntarily terminated employees and retention bonuses paid to certain employees due to the South Texas asset divestiture. This compares to $.7 million of employee-related Panhandle asset divestiture costs included in the six months ended June 30, 2014. Related to the decrease in labor costs, capitalized general and administrative costs decreased $3 million, or 39%, in the second quarter of 2014 as compared to the second quarter of 2013, and $8 million, or 52%, in the six months ended June 30, 2014 as compared to the six months ended June 30, 2013.

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Stock-based compensation costs, net of costs capitalized, decreased $1 million and $5 million during the three and six months ended June 30, 2014 as compared to the three and six months ended June 30, 2013. The decreases were primarily due to a reduction in employee headcount and a decrease in the Company’s stock price from the second quarter of 2013 to the second quarter of 2014. The reduction in employee headcount was due both to involuntary terminations, which occurred primarily in the first and fourth quarters of 2013 and in which case awards vest and expense is accelerated, and voluntary terminations, in which case awards do not vest and previously recognized expense is reversed.

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 June 30,								Six Months Ended June 30,
	2014				2013				2014				2013
	In Thousands		$/Mcfe		In Thousands		$/Mcfe		In Thousands		$/Mcfe		In Thousands		$/Mcfe
Depletion	$	19,396	$	2.14	$	41,671	$	2.17	$	39,660	$	2.14	$	89,209	$	2.17
Depreciation	907		.10		2,133		.11		2,058		.11		3,138		.08
Depreciation, depletion, and amortization	$	20,303	$	2.24	$	43,804	$	2.28	$	41,718	$	2.25	$	92,347	$	2.25

Depreciation, depletion, and amortization expense (“DD&A”) in the second quarter of 2014 was $20 million, or $2.24 per Mcfe, compared to $44 million, or $2.28 per Mcfe, in the second quarter of 2013. For the first six months of 2014, DD&A was $42 million, or $2.25 per Mcfe, compared to $92 million, or $2.25 per Mcfe, in the first six months of 2013.

The decreases in DD&A in the three and six months ended June 30, 2014 as compared to the three and six months ended June 30, 2013 are due primarily to decreases in our oil and natural gas reserves, with such decreases primarily attributable to our property divestitures, partially offset by oil reserve additions, which typically have higher per-unit development costs than natural gas reserves.

Ceiling Test Write-Down

At June 30, 2014 we recorded a $77 million ceiling test write-down of our United States cost center pursuant to the full cost ceiling test limitation prescribed by the SEC. This ceiling test write-down was primarily a result of (i) a reduction in the estimated reserves attributable to a portion of our proved undeveloped locations in the Eagle Ford and (ii) a reduction in the total number of proved undeveloped locations in the Eagle Ford to properly align the number of future drilling locations with our current development pace relative to the SEC five year limitation on the age of proved undeveloped locations. Additional write-downs of our oil and natural gas properties may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenues from estimated production of proved oil and natural gas reserves declines compared to prices used as of June 30, 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.

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Interest Expense

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



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014		2013			2014		2013
	(In Thousands)
Credit facility⁽¹⁾	$	480	$	1,901		$	1,507	$	3,528
7¼% senior notes due 2019⁽¹⁾	10,660		18,445			21,317		36,887
7½% senior notes due 2020⁽¹⁾	4,300		9,677			8,599		19,350
8½% senior notes due 2014⁽¹⁾	—		—			—		6,277
Other	298		292			326		592
Interest costs capitalized	—		(923		)	—		(1,114		)
Interest expense	$	15,738	$	29,392		$	31,749	$	65,520

___________________________________________


(1)	Interest expense amounts include interest on the principal or borrowings outstanding, amortization of debt issuance costs, and amortization of discounts and premiums, all as applicable.

Interest expense was $16 million and $29 million for the three months ended June 30, 2014 and 2013, respectively, and $32 million and $66 million for the six months ended June 30, 2014 and 2013, respectively. The $14 million decrease in the second quarter of 2014 compared to the second quarter of 2013 was comprised primarily of $13 million due to the redemption of $700 million of 7¼% senior notes and 7½% senior notes in November 2013. The $34 million decrease in the first six months of 2014 compared to the first six months of 2013 was comprised primarily of the following: (i) $26 million due to the redemption of $700 million of 7¼% senior notes and 7½% senior notes in November 2013 and (ii) $6 million due to the redemption of the $300 million of 8½% senior notes in March 2013. Additionally, there were no borrowings outstanding under our credit facility during the first six months of 2014 whereas there were borrowings outstanding under our credit facility during the first six months of 2013. See “Liquidity and Capital Resources—Bank Credit Facility” below for more information regarding our credit facility. Other interest expense consists primarily of interest accrued on the previously disclosed arbitration award in the proceeding styled Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al.. See Part II, Item 1 “Legal Proceedings—Other Proceedings” for more information regarding this matter. Interest costs capitalized relate to our investments in significant unproved acreage positions that are under development.

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 primarily on the specific terms of the derivative instruments to which we are a party and third-party indices’ settlement prices or interest rates, as the case may be. See Note 7 and Note 8 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014		2013
	(In Thousands)
Realized losses (gains) on derivative instruments, net:
Oil	$	2,433		$	(473	)	$	3,465	$	(901	)
Natural gas	1,863			1,579			5,291		(7,642		)
Interest	—			(9,803		)	—		(12,885		)
Subtotal realized losses (gains) on derivative instruments, net	4,296			(8,697		)	8,756		(21,428		)
Unrealized losses (gains) on derivative instruments, net:
Oil	7,608			(5,736		)	9,645		(6,044		)
Natural gas	(263		)	(27,087		)	6,091		8,382
Interest	—			9,910			—		13,060
Subtotal unrealized losses (gains) on derivative instruments, net	7,345			(22,913		)	15,736		15,398
Realized and unrealized losses (gains) on derivative instruments, net	$	11,641		$	(31,610	)	$	24,492	$	(6,030	)

Other, Net

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In Thousands)
Accretion of asset retirement obligations	$	381		$	549		$	894		$	1,793
Write-off of debt issuance costs	—			—			3,323			—
Loss on debt extinguishment	—			—			—			25,223
Gain on asset dispositions, net	(22,185		)	—			(21,391		)	—
Merger-related costs	10,202			—			10,202			—
Rig stacking/lease termination	3,075			1,258			8,259			4,296
Other, net	(775		)	(214		)	(1,941		)	(899		)
	$	(9,302	)	$	1,593		$	(654	)	$	30,413

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

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Income Tax

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In Thousands, Except Percentages)
Current income tax (benefit) expense	$	(78	)	$	(212	)	$	(1,292	)	$	125
Deferred income tax	—			—			—			—
Total income tax (benefit) expense	$	(78	)	$	(212	)	$	(1,292	)	$	125
Effective income tax rate	.1		%	(.6		)%	1.2		%	(.4		)%

Our effective income tax rates were .1% and 1.2% for the three and six months ended June 30, 2014, respectively, and (.6)% and (.4)% for the three and six months ended June 30, 2013, respectively. The significant differences between our blended federal and state statutory income tax rate of approximately 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 August 14, 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 June 30, 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 June 30, 2014, as calculated in accordance with the credit facility, was 5.07. We had no borrowings outstanding under the credit facility as of June 30, 2014 and we had outstanding borrowings of $12 million as of August 14, 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.

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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 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 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 proceeds of $985 million, which we used 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. As noted below under “Bank Credit Facility,” based on our current projections, the ratio of total debt to EBITDA may exceed the maximum allowed under the credit facility sometime prior to the end of 2014 if we do not obtain a waiver or an additional amendment to the credit facility. If we are unable to obtain a waiver or an amendment, the credit facility could be terminated. However, we believe we can arrange for alternative sources of debt financing, including securing liens against our properties or selling additional properties, sufficient to meet our recurring operating needs and 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 June 30, 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, where it remained at June 30, 2014.

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

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issued senior notes, excluding any senior unsecured notes that we or any of our Restricted Subsidiaries may issue to refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if we or any of our Restricted Subsidiaries sell oil and natural gas properties having a fair market value, including any economic loss of unwinding any related hedging agreement, in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount either (i) equal to the percentage of the borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by us and the required lenders. The sale of our South Texas properties resulted in a $170 million reduction to the borrowing base when the transaction closed in February 2013 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 June 30, 2014, as calculated in accordance with the Credit Facility, was 5.07.

Based on our current projections, the ratio of total debt to EBITDA may exceed the maximum allowed under the Credit Facility sometime prior to the end of 2014 if we do not obtain a waiver or an additional amendment to the Credit Facility. We believe that we will be able to obtain such a waiver or an amendment prior to the ratio exceeding the maximum amount currently allowed. If we fail to obtain an amendment, the Credit Facility could be terminated. However, we believe we can obtain alternative sources of debt financing sufficient for our needs, including securing liens against our properties or selling additional properties.

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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 June 30, 2014, there were no outstanding borrowings under the Credit Facility and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $298 million. However, based on the ratio of total debt to EBITDA discussed above, our borrowing utilization of the Credit Facility was limited to approximately $106 million at June 30, 2014. At August 14, 2014, there were outstanding borrowings of $12 million under the Credit Facility bearing interest at 3.8%, and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $286 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 August 14, 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 six months ended June 30, 2014 and 2013 were as follows:



	Six Months Ended
	June 30,
	2014			2013
	(In Thousands)
Net cash provided by operating activities	$	13,733		$	110,412
Net cash (used) provided by investing activities	(75,435		)	132,763
Net cash provided (used) by financing activities	10,092			(243,810		)

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 six months ended June 30, 2014 compared to the six months ended June 30, 2013, was primarily due to the divestitures of oil and natural gas properties in South Texas and the Texas Panhandle, which occurred in February 2013 and November 2013, respectively, which caused decreased revenues partially offset by lower production, general and administrative, and interest expenses in 2014 as compared to 2013. Also contributing to the decrease in net cash provided by operating activities were increased cash expenses related to rig

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stacking and operating lease terminations in 2014 as compared to 2013 (see Note 9 to the Condensed Consolidated Financial Statements for more information on rig stacking and lease terminations) and an increased investment in working capital in 2014 as compared to 2013.

The components of net cash (used) provided by investing activities for the six months ended June 30, 2014 and 2013 were as follows:



	Six Months Ended
	June 30,
	2014			2013
	(In Thousands)
Exploration, development, and leasehold acquisition costs⁽¹⁾	$	(94,786	)	$	(205,099	)
Proceeds from sales of assets	24,145			338,977
Other property and equipment	(4,794		)	(1,115		)
Net cash (used) provided by investing activities	$	(75,435	)	$	132,763

____________________________________________

(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) provided by investing activities in the six months ended June 30, 2014 compared to the corresponding period of 2013 was primarily due to a decrease in proceeds from the sales 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 six months ended June 30, 2014 as compared to the six months ended June 30, 2013 due to the Texas Panhandle divestiture that occurred in November 2013. Acquisition, exploration, and development expenditures for the Texas Panhandle properties approximated $94 million during the six months ended June 30, 2013. Proceeds from sales of assets in the six months ended June 30, 2014 included $20 million that we received in May 2014 for the Texas Panhandle divestiture. Proceeds from the sales of assets in the six months ended June 30, 2013 included $321 million for the South Texas divestiture.

Net cash provided by financing activities of $10 million during the six months ended June 30, 2014 consisted primarily of a change in bank overdrafts of $11 million. Net cash used by financing activities of $244 million during the six months ended June 30, 2013 consisted primarily of $321 million used for the redemption of the 8½% senior notes due 2014, offset partially by net proceeds from bank borrowings of $65 million, and a change in bank overdrafts of $14 million.

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Capital Expenditures

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In Thousands)
Exploration, development, and acquisition costs:
Direct costs:
Exploration and development	$	47,311	$	63,151	$	88,553	$	178,974
Leasehold acquisitions	302		1,461		390		4,066
Overhead capitalized	4,851		8,098		9,409		20,396
Interest capitalized	—		923		—		1,114
Total capital expenditures⁽¹⁾	$	52,464	$	73,633	$	98,352	$	204,550

____________________________________________

(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 $(.4) million and $.4 million recorded during the three months ended June 30, 2014 and 2013, respectively, and $(1) million and $1 million recorded during the six months ended June 30, 2014 and 2013, respectively.

Based on our year-to-date capital expenditures of $98 million and our remaining budgeted capital expenditures for the second half of 2014, we expect to incur between $240 million to $250 million of capital expenditures in 2014. 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.

RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 is the result of a joint project with the International Accounting Standards Board intended to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. generally accepted accounting principles and International Financial Reporting Standards. The guidance is expected to enhance comparability of revenue recognition practices across entities, industries, jurisdictions, and capital markets. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. Entities must adopt ASU 2014-09 using either a full retrospective approach or a modified retrospective approach with a cumulative effect of adoption recognized in the opening balance of retained earnings at the date of adoption. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. We have not yet determined the effect that adoption of ASU 2014-09 will have on our financial statements, nor have we determined which transition method we will use upon adoption.

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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 may include statements with respect to, among other things:


•	estimates of our oil and natural gas reserves;


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


•	our future financial condition, 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 from the proposed combination transaction.

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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 and the risks described in Part II, Item 1A, “Risk Factors” in this Form 10-Q.

Should one or more of the risks or uncertainties described above or elsewhere in this report 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 report and attributable to Forest are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or persons acting on our behalf may issue.

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RECONCILIATION OF NON-GAAP MEASURE

Adjusted EBITDA

In addition to reporting net earnings (loss) as defined under GAAP, we also present adjusted 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 earnings (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), ceiling test write-downs of oil and natural gas properties, 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 earnings (loss) (its most comparable GAAP financial measure), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating interest, taxes, depreciation, depletion, amortization, and other items from earnings, we believe the result is a useful measure across time in evaluating our fundamental core operating performance. Management also uses Adjusted EBITDA to manage our business, including in preparing our annual operating budget and financial projections. We believe that Adjusted EBITDA is also useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in the oil and gas industry. Our management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) and revenues, to measure operating performance. The following table provides a reconciliation of net earnings (loss), the most directly comparable GAAP measure, to Adjusted EBITDA for the periods presented.



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In Thousands)
Net earnings (loss)	$	(82,717	)	$	33,439		$	(103,724	)	$	(34,509	)
Income tax (benefit) expense	(78		)	(212		)	(1,292		)	125
Unrealized losses (gains) on derivative instruments, net	7,345			(22,913		)	15,736			15,398
Interest expense	15,738			29,392			31,749			65,520
Gain on asset dispositions, net	(22,185		)	—			(21,391		)	—
Write-off of debt issuance costs	—			—			3,323			—
Loss on debt extinguishment	—			—			—			25,223
Accretion of asset retirement obligations	381			549			894			1,793
Ceiling test write-down of oil and natural gas properties	77,176			—			77,176			—
Depreciation, depletion, and amortization	20,303			43,804			41,718			92,347
Stock-based compensation	1,500			2,832			2,294			6,479
Merger-related costs	10,202			—			10,202			—
Employee-related asset divestiture costs	156			—			735			5,821
Rig stacking/lease termination	3,075			1,258			8,259			4,296
Adjusted EBITDA	$	30,896		$	88,149		$	65,679		$	182,493

The $57 million and $117 million decreases in Adjusted EBITDA between the three-month and six-month periods, respectively, were 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”.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

Swaps

In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher than the fixed price, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. The table below sets forth our outstanding swaps as of June 30, 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)
July 2014 - December 2014	70	$	4.38	$	(1,026	)	3,500	$	95.34	$	(5,025	)
Calendar 2015	50	4.21		(229		)	1,000	89.25		(2,658		)

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 June 30, 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	$	393
Calendar 2015	10	4.10/4.30	(109		)

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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 June 30, 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)
Natural Gas Swaptions:
Calendar 2016	December 2014	10	$	4.18	$	(800	)	—	$	—	$	—
Oil Swaptions:
Calendar 2015	December 2014	—	—		—			3,000	100.00		(2,648		)
Calendar 2015	December 2014	—	—		—			1,000	106.00		(339		)
Calendar 2015	December 2014	—	—		—			1,000	99.00		(1,017		)
Calendar 2016	December 2015	—	—		—			1,000	98.00		(1,226		)
Oil Put Options:
Monthly Calendar 2014	Monthly Calendar 2014	—	—		—			2,000	70.00		(1		)

The estimated fair value at June 30, 2014 of all our commodity derivative instruments based on various valuation inputs, including published forward prices, was a net liability of approximately $15 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 six months ended June 30, 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 June 30, 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	(24,491		)
Net cash settlements paid	8,756
As of June 30, 2014	$	(14,685	)

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Interest Rate Risk

The following table presents principal amounts and related interest rates by year of maturity for senior notes at June 30, 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 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

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 June 30, 2014 (the “Evaluation Date”). Because of the matters disclosed in the Form 8-K of Forest filed on August 11, 2014, Messrs. McDonald and Wind have concluded that as of the Evaluation Date our disclosure controls and procedures were not 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 June 30, 2014 that has materially affected, or is likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Proceedings Related to the Transaction with Sabine

Since the announcement of our merger agreement with Sabine, six putative shareholder class action complaints have been filed in the Supreme Court of the State of New York by purported Forest common shareholders. These actions are captioned Stourbridge Investments LLC v. Forest Oil Corp., et al., Index No. 651418/2014, filed May 7, 2014; Raul, et al. v. Carroll, et al., Index No. 651446/2014, filed May 9, 2014; Rothenberg v. Forest Oil Corp., et al., Index No. 651499/2014, filed May 15, 2014; Gawlikowski v. Forest Oil Corp., et al., Index No. 651506/2014, filed May 16, 2014; Edwards v. Carroll, et al., Index No. 651523/2014, filed May 16, 2014; and Jabri v. Forest Oil Corp., et al., Index No. 651551/2014, filed May 20, 2014. On July 8, 2014, the New York Court consolidated the New York actions and captioned the case In re Forest Oil Corporation Shareholder Litigation, Index No. 651418/2014, and on July 17, 2014, the New York plaintiffs filed an amended consolidated complaint (the “New York Action”). The New York Action names as defendants each of the current directors of Forest, as well as Sabine and certain of its affiliates and investors, and seeks, among other things, to enjoin the combination transaction or, in the event the combination transaction is consummated, to recover damages. The action alleges, among other things, that the members of the Forest board of directors breached their fiduciary duties to Forest shareholders by agreeing to the original transaction announced by Forest and Sabine on May 6, 2014 for inadequate consideration and pursuant to an inadequate process, that the revised transaction structure announced by Forest and Sabine on July 10, 2014 was structured to deprive Forest shareholders of their right to vote on the combination transaction, and that the disclosures made by Forest in the Schedule 14A proxy statement filed on July 16, 2014 were inadequate. The New York Action also includes allegations challenging the Company’s sale of its Texas Panhandle assets to Templar Energy, which closed on November 25, 2013. The New York Action further alleges that Sabine and certain of its affiliates aided and abetted these alleged breaches.

One putative shareholder class action complaint has been filed in the United States District Court for the District of Colorado by two purported Forest common shareholders (the “Colorado Action”), captioned Olinatz v. Forest Oil Corp., et al., Case No. 1:14-cv-01409, filed May 19, 2014. The plaintiffs in the Colorado Action filed an amended complaint on June 13, 2014. The Colorado Action names as defendants each of the current directors of Forest, as well as Forest, Sabine Holdings, and certain of their respective affiliate entities. The action seeks, among other things, to enjoin the original transaction or, in the event the original transaction is consummated, to recover damages. The action alleges, among other things, that the members of the Forest board of directors breached their fiduciary duties to Forest shareholders by agreeing to sell Forest transaction for inadequate consideration and pursuant to an inadequate process, and that certain of the entity defendants, including Sabine Holdings and certain of its affiliates, aided and abetted these alleged breaches. In addition, the Colorado Action further alleges violations of the federal securities laws in connection with Forest’s disclosures in the Form S-4 registration statement filed by Forest on May 29, 2014.

Forest believes the allegations in all complaints related to the transaction with Sabine are without merit.

Other 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,

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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 appealed the verdict, and appellate briefs have been submitted. A date for oral arguments has not yet been set.

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al., which occurred in Harris County, Texas. The third member of the arbitration panel dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration decision awarded the claimant $23 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest appealed the judgment to the Court of Appeals for the First District of the State of Texas. The judgment was affirmed on July 24, 2014. Forest is now seeking a rehearing before the Court of Appeals and, failing that, will seek to have the judgment reversed at the Supreme Court for the State of Texas.

Except as noted above and in Part II, Item 1, of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, there have been no material changes to the disclosure included in Part I, Item 3, of the Annual Report on Form 10-K for the year ended December 31, 2013.

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

Item 1A. RISK FACTORS

The following risk factors update the Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2013 (the “Annual Report”). Except as set forth below, there have been no material changes to the risks described in Part I, Item 1A, of the Annual Report.

The pendency of the transaction between Forest and Sabine could materially adversely affect our future business and operations or result in a loss of our respective employees.

Uncertainty about the effect of the transaction on employees, customers, and suppliers may have an adverse effect on Forest’s business. These uncertainties may impair our ability to attract, retain, and motivate key personnel until the transaction is consummated and for a period of time thereafter, and could cause customers, suppliers, and others who deal with Forest to change their existing business relationships, which could negatively affect revenues, earnings, and cash flows of Forest, as well as the market price of Forest common shares, regardless of whether the transaction is completed. Employee retention may be particularly challenging during the pendency of the transaction because employees may experience uncertainty about their future roles with the combined company. If, despite Forest’s retention efforts, key employees depart because of issues relating to the uncertainty and difficulty of

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integration or a desire not to remain with the combined company, Forest’s business could be seriously harmed. Similar risks could affect Sabine, and therefore the combined company if the transaction is completed.

The transaction with Sabine is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all. Failure to complete the transaction, or significant delays in completing the transaction, could negatively affect our share price and our future business and financial results.

The completion of the transaction is subject to a number of conditions, including approval of the issuance of shares to Sabine and an amendment to our certificate of incorporation to increase our outstanding shares, which make the completion and timing of the transaction uncertain. Also, either Forest or Sabine may terminate the agreement if the merger has not been completed on or before December 31, 2014.

If the agreement is terminated, or if there are significant delays in completing the merger, there may be various consequences, including:


•	our business may have been adversely affected by the failure to pursue other beneficial opportunities due to the focus of management on the transaction and certain restrictions under the agreement, without realizing any of the anticipated benefits of completing the transaction;


•	we will have paid certain costs relating to the transaction, such as legal, accounting, financial advisor and printing fees, without realizing any of the anticipated benefits of completing the transaction;


•	the market price of our common shares might decline to the extent that the current market price reflects a market assumption that the transaction will be completed;


•	we may experience negative reactions from the financial markets and from our customers and employees and/or could be subject to litigation related to a failure to complete the transaction or to enforce our obligations under the agreement;


•	we might have to consider future asset dispositions and other transactions;


•	if the agreement is terminated under certain circumstances, we may be required to pay a termination fee of $15.0 million to Sabine; and


•	if our board seeks out another merger or business combination following termination of the agreement, our common shareholders cannot be certain that we will be able to find a party willing to enter into a more or equally favorable arrangement than the terms provided for in the agreement.

The agreement with Sabine includes restrictions relating to the conduct of our business while the transaction is pending, which could adversely affect our business and operations.

Under the terms of the agreement, we are subject to certain restrictions on the conduct of our business prior to completing the transaction, which may adversely affect our ability to execute certain of our business strategies, including, subject to certain exceptions, to acquire or dispose of assets, incur capital expenditures, enter into contracts, incur indebtedness or settle claims and lawsuits, unless we obtain the prior written consent of Sabine. Such limitations could negatively affect our business and operations prior to the completion of the transaction.

The transaction with Sabine, if completed, will result in a default under our credit agreement and will trigger a mandatory repurchase offer under our existing indentures.

The transaction, if completed, will also result in a change of control as defined in our credit agreement. The occurrence of a change of control is an event of default under our credit agreement. If our credit agreement is not refinanced or amended in connection with the transaction with Sabine, the counterparties may exercise their rights and remedies under such credit agreement.

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The transaction, if completed, will result in a change of control as defined in our indentures. The occurrence of a change of control triggers an obligation for us to make a change of control offer for the outstanding notes at 101% of their principal amount, plus accrued and unpaid interest to the purchase date pursuant to the terms of the relevant indenture. If, following the occurrence of the change of control, each change of control offer is not made pursuant to the terms of the relevant indenture, the bondholders may exercise their rights and remedies under such indenture to accelerate the notes and all obligations in respect thereof. In addition, we may not be able to repurchase the notes upon a change of control because we may not have sufficient financial resources to purchase all of the debt securities that are tendered upon a change of control and repay other indebtedness that will become due.

Pending litigation against us related to the transaction with Sabine could prevent or delay completion of the merger, require payment of damages in the event that the transaction is completed and/or may adversely affect the combined company’s business, financial condition or results of operations following the merger.

Purported shareholder class actions have been filed against, among others, Forest and the members of our board. These actions seek, among other things, an injunction barring or rescinding the merger, and damages in the event the merger is consummated. Although we believe that the claims asserted in the lawsuits are without merit, we can provide no assurance as to the outcome of these claims. An adverse judgment for monetary damages could have a material adverse effect on the operations of Forest after the completion of the transaction. A preliminary injunction could delay or jeopardize the completion of the transaction, and an adverse judgment granting injunctive relief could permanently enjoin the completion of the transaction.

Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our bank credit facility and the indentures governing our senior notes contain restrictive covenants that limit our ability and the ability of certain of our subsidiaries to, among other things:


•	incur or guarantee additional indebtedness or issue preferred shares;


•	pay dividends or make other distributions;


•	purchase equity interests or redeem subordinated indebtedness early;


•	create or incur certain liens;


•	enter into transactions with affiliates; and


•	sell assets or merge or consolidate with another company.

Complying with the restrictions contained in some of these covenants will require us to meet certain financial ratios and tests, notably with respect to consolidated interest coverage, total assets, net debt, equity, and net income. For example, our bank credit facility provides 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 a specified amount. In September 2013, we amended the facility to increase the permitted ratio to 5.0 to 1.0 for any time after September 11, 2013 up to and including March 31, 2014, and to 4.75 to 1.0 for any time after April 1, 2014 up to and including June 30, 2014. After June 30, 2014, the ratio would have returned to the original 4.5 to 1.0. In March 2014, we again amended the facility to increase the permitted ratio even further. Under the second amendment, Forest shall not permit, as of the last day of any fiscal quarter, the ratio of total debt as of such date to EBITDA to be greater than (i) at the end of any calendar quarters ending on March 31, 2014, June 30, 2014, and September 30, 2014, 5.75 to 1.0, (ii) at the end of the calendar quarter ending December 31, 2014, 5.50 to 1.0, (iii) at the end of the calendar quarter ending March 31, 2015, 5.25 to 1.0, (iv) at the end of the calendar quarter ending June 30, 2015, 5.00 to 1.0, (e) at the end of the calendar quarter ending September 30, 2015, 4.75 to 1.0, and (f) at the end of any calendar quarter ending after September 30, 2015, 4.50 to 1.0.

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Our ratio of total debt to EBITDA for the four consecutive fiscal quarter period ending June 30, 2014, as calculated in accordance with our bank credit facility, was 5.07. Based on our current projections, absent an amendment or waiver to the bank credit facility, the ratio of total debt to EBITDA may exceed the maximum allowed sometime prior to the end of 2014. Non-compliance with the terms of our debt covenants or other credit provisions could result in all amounts outstanding under our bank credit facility and, potentially, our indentures, becoming due and payable immediately, and the resultant termination of our bank credit facility. This would result, at a minimum, in the need to slow or cease the incurrence of capital and operational expenditures, which would have a negative impact on our expected production, revenues and, potentially, on our reserves. At worst, it could also result in foreclosure of our assets and potential bankruptcy. See Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a more complete discussion of our debt obligations and liquidity.

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

Unregistered Sales of Equity Securities

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

Issuer Purchases of Equity Securities

The table below sets forth information regarding repurchases of our common stock during the second 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
April 2014	11,183	$	1.87	—	—
May 2014	—	—		—	—
June 2014	100,202	2.40		—	—
Second Quarter Total	111,385	$	2.35	—	—

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Item 6. EXHIBITS



(a)			Exhibits.

2.1			Agreement and Plan of Merger, dated as of May 5, 2014, by and among Sabine Investor Holdings LLC, Sabine Oil & Gas Holdings LLC, Sabine Oil & Gas Holdings II LLC, Sabine Oil & Gas LLC, Forest Oil Corporation, New Forest Oil Inc. and Forest Oil Merger Sub Inc., incorporated herein by reference to Exhibit 2.1 to Form 8-K for Forest Oil Corporation filed May 6, 2014.

2.2			Amended and Restated Agreement and Plan of Merger, dated as of July 9, 2014, by and among Sabine Investor Holdings LLC, Sabine Oil & Gas Holdings LLC, Sabine Oil & Gas Holdings II LLC, Sabine Oil & Gas LLC, Forest Oil Corporation and FR XI Onshore AIV, LLC., incorporated by reference to Exhibit 2.1 to Form 8-K for Forest Oil Corporation on July 10, 2014.

3.1*			Restated Certificate of Incorporation of Forest Oil Corporation, as amended through July 10, 2014.

3.2			Certificate of Amendment for Forest Oil Corporation’s Series A Junior Participating Preferred Stock, incorporated herein by reference to Exhibit 3.1 to Form 8-K for Forest Oil Corporation on July 10, 2014.

3.3			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			Rights Agreement, dated as of July 9, 2014, between Forest Oil Corporation and Computershare Inc., incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation filed July 10, 2014.

10.1			Stockholder’s Agreement, dated as of May 5, 2014, by and among Sabine Investor Holdings LLC, Forest Oil Corporation and New Forest Oil Inc., incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 6, 2014.

10.2			Amended and Restated Stockholder’s Agreement, dated as of July 9, 2014, by and among Sabine Investor Holdings LLC, Forest Oil Corporation and FR XI Onshore AIV, LLC., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed July 10, 2014.

10.3			Registration Rights Agreement, dated as of May 5, 2014, by and among Sabine Investor Holdings LLC, Forest Oil Corporation and New Forest Oil Inc., incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed May 6, 2014.

10.4			Amended and Restated Registration Rights Agreement, dated as of July 9, 2014, by and among Sabine Investor Holdings LLC, FR XI Onshore AIV, LLC and Forest Oil Corporation, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed July 10, 2014.

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.

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(a)			Exhibits.

99.1			Form of Certificate of Amendment (Evidencing Preferred Stock), incorporated herein by reference to Exhibit 99.1 to Form 8-K for Forest Oil Corporation filed July 15, 2014.

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.

+ Omitted pursuant to Rule 12b-25.

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

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SIGNATURES

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



	FOREST OIL CORPORATION (Registrant)

August 18, 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)

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Exhibit Index



2.1			Agreement and Plan of Merger, dated as of May 5, 2014, by and among Sabine Investor Holdings LLC, Sabine Oil & Gas Holdings LLC, Sabine Oil & Gas Holdings II LLC, Sabine Oil & Gas LLC, Forest Oil Corporation, New Forest Oil Inc. and Forest Oil Merger Sub Inc., incorporated herein by reference to Exhibit 2.1 to Form 8-K for Forest Oil Corporation filed May 6, 2014.

2.2			Amended and Restated Agreement and Plan of Merger, dated as of July 9, 2014, by and among Sabine Investor Holdings LLC, Sabine Oil & Gas Holdings LLC, Sabine Oil & Gas Holdings II LLC, Sabine Oil & Gas LLC, Forest Oil Corporation and FR XI Onshore AIV, LLC., incorporated by reference to Exhibit 2.1 to Form 8-K for Forest Oil Corporation on July 10, 2014.

3.1*			Restated Certificate of Incorporation of Forest Oil Corporation, as amended through July 10, 2014.

3.2			Certificate of Amendment for Forest Oil Corporation’s Series A Junior Participating Preferred Stock, incorporated herein by reference to Exhibit 3.1 to Form 8-K for Forest Oil Corporation on July 10, 2014.

3.3			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			Rights Agreement, dated as of July 9, 2014, between Forest Oil Corporation and Computershare Inc., incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation filed July 10, 2014.

10.1			Stockholder’s Agreement, dated as of May 5, 2014, by and among Sabine Investor Holdings LLC, Forest Oil Corporation and New Forest Oil Inc., incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 6, 2014.

10.2			Amended and Restated Stockholder’s Agreement, dated as of July 9, 2014, by and among Sabine Investor Holdings LLC, Forest Oil Corporation and FR XI Onshore AIV, LLC., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed July 10, 2014.

10.3			Registration Rights Agreement, dated as of May 5, 2014, by and among Sabine Investor Holdings LLC, Forest Oil Corporation and New Forest Oil Inc., incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed May 6, 2014.

10.4			Amended and Restated Registration Rights Agreement, dated as of July 9, 2014, by and among Sabine Investor Holdings LLC, FR XI Onshore AIV, LLC and Forest Oil Corporation, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed July 10, 2014.

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.

99.1			Form of Certificate of Amendment (Evidencing Preferred Stock), incorporated herein by reference to Exhibit 99.1 to Form 8-K for Forest Oil Corporation filed July 15, 2014.

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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.

+ Omitted pursuant to Rule 12b-25.