SABINE OIL & GAS CORP - FORM 10-Q/A - October 1, 2014

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
__________________________________________________
FORM 10-Q/A
(Amendment No. 1) 
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2014
 
or 
¨
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.  ¨ Yes  x No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes  ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
Accelerated filer x
Non-accelerated filer ¨
(Do not check if a smaller reporting company)
Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨ Yes  x No

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


FOREST OIL CORPORATION
INDEX TO FORM 10-Q/A
March 31, 2014
 


i

EXPLANATORY NOTE

As previously disclosed in Item 8.01 of our Current Report on Form 8-K filed on August 11, 2014 (the “Form 8-K”), Forest’s management has determined that certain material weaknesses existed in our internal control over financial reporting at year end 2013. Our independent registered public accounting firm, Ernst & Young LLP (“EY”) has reached the same conclusion. Accordingly, we disclosed that our internal control over financial reporting was ineffective at December 31, 2013, and that both management’s assessment of, and EY’s report on, internal control over financial reporting as of December 31, 2013, included in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed on February 26, 2014 (the “Form 10-K”), should no longer be relied upon. We also disclosed management’s determination that Forest’s disclosure controls and procedures were not effective at a reasonable level as of December 31, 2013 and March 31, 2014. Finally, we disclosed that EY and Forest would perform additional testing of Forest’s (i) internal control over financial reporting for the year ended December 31, 2013 and (ii) financial statements for each of the three years included in the Form 10-K.
The additional testing of Forest’s internal control over financial reporting, and the financial statements, has now been completed. We note that the additional testing did not result in a restatement of the financial statements included in the Form 10-K or in the Form 10-Q for the quarterly period ended March 31, 2014 (the Original 10-Q”). Forest has filed Amendment No. 1 (the “Form 10-K/A”) to the Form 10-K to (i) disclose the material weaknesses in our internal control over financial reporting that have been identified since the date of the Form 10-K and (ii) include an audit opinion by EY that has been amended, relative to the audit opinion included in the Form 10-K, to include disclosure regarding EY’s opinion of our ability to continue to operate as a going concern. We are now filing this Amendment No. 1 (this “Form 10-Q/A”) to the Original 10-Q, also to address the material weaknesses and “going concern” issues identified above.
This Form 10-Q/A sets forth the Original 10-Q in its entirety; however, pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), this Form 10-Q/A amends and restates only the following Items of the Original 10-Q, and only with respect to matters relating to the material weaknesses in internal control over financial reporting and the going concern disclosure:

Part I
•
Item 1. Financial Statements
•
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
•
Item 4. Controls and Procedures
Part II
•
Item 6. Exhibits

With respect to Part II, Item 6, we are including for filing with this Form 10-Q/A only (i) certifications from our Chief Executive Officer and Chief Financial Officer as Exhibits 31.1, 31.2, 32.1, and 32.2, and (ii) various exhibits related to XBRL. In addition, we are enhancing the disclosure in Part I, Item 2 in order to comply with comments received from the staff of the Securities and Exchange Commission. As noted above, the additional testing on the financial statements and on our internal control over financial reporting did not result in a restatement of the financial statements included in the Form 10-K or in the Original 10-Q.
Except as otherwise set forth in this Explanatory Note, this Form 10-Q/A does not modify or update other disclosures presented in the Original 10-Q, except as necessary to make the disclosure herein consistent with updated disclosures contained in the Form 10-K/A. Accordingly, except for the items identified above, this Form 10-Q/A speaks as of May 6, 2014, the filing date of the Original 10-Q, and any forward-looking statements represent management’s views as of the date of the Original 10-Q and should not be assumed to be correct as of any date thereafter. This Form 10-Q/A should be read in conjunction with our other filings made with the Securities and Exchange Commission subsequent to the date of the Original 10-Q.


 


ii

PART I—FINANCIAL INFORMATION
 
Item 1.  FINANCIAL STATEMENTS
  
FOREST OIL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS 
(Unaudited)
(In Thousands, Except Share Amounts)
 
March 31,
2014
 
December 31,
2013
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
48,328

 
$
66,192

Accounts receivable
32,840

 
35,654

Derivative instruments
713

 
5,192

Other current assets
23,871

 
6,756

Total current assets
105,752

 
113,794

Property and equipment, at cost:
 

 
 

Oil and natural gas properties, full cost method of accounting:
 

 
 

Proved, net of accumulated depletion of $8,480,853 and $8,460,589
776,413

 
753,079

Unproved
54,612

 
53,645

Net oil and natural gas properties
831,025

 
806,724

Other property and equipment, net of accumulated depreciation and amortization of $46,991 and $50,058
10,693

 
11,845

Net property and equipment
841,718

 
818,569

Deferred income taxes
1,762

 
2,230

Goodwill
134,434

 
134,434

Derivative instruments
2,216

 
400

Other assets
16,305

 
48,525

 
$
1,102,187

 
$
1,117,952

LIABILITIES AND SHAREHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued liabilities
$
149,525

 
$
141,107

Accrued interest
13,445

 
6,654

Derivative instruments
9,598

 
4,542

Deferred income taxes
1,762

 
2,230

Other current liabilities
5,847

 
12,201

Total current liabilities
180,177

 
166,734

Long-term debt
800,171

 
800,179

Asset retirement obligations
24,337

 
22,629

Derivative instruments
672

 
—

Other liabilities
61,945

 
73,941

Total liabilities
1,067,302

 
1,063,483

Shareholders’ equity:
 

 
 

Preferred stock, none issued and outstanding
—

 
—

Common stock, 119,099,106 and 119,399,983 shares issued and outstanding
11,910

 
11,940

Capital surplus
2,556,277

 
2,554,997

Accumulated deficit
(2,523,077
)
 
(2,502,070
)
Accumulated other comprehensive loss
(10,225
)
 
(10,398
)
Total shareholders’ equity
34,885

 
54,469

 
$
1,102,187

 
$
1,117,952


See accompanying Notes to Condensed Consolidated Financial Statements. 


1

FOREST OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In Thousands, Except Per Share Amounts)
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
Revenues:
 

 
 

Oil, natural gas, and natural gas liquids sales
$
64,457

 
$
118,042

Interest and other
737

 
132

Total revenues
65,194

 
118,174

Costs, expenses, and other:
 

 
 

Lease operating expenses
14,510

 
21,204

Production and property taxes
3,225

 
2,216

Transportation and processing costs
2,515

 
3,280

General and administrative
8,240

 
20,014

Depreciation, depletion, and amortization
21,415

 
48,543

Interest expense
16,011

 
36,128

Realized and unrealized losses on derivative instruments, net
12,851

 
25,580

Other, net
8,648

 
28,820

Total costs, expenses, and other
87,415

 
185,785

Loss before income taxes
(22,221
)
 
(67,611
)
Income tax (benefit) expense
(1,214
)
 
337

Net loss
$
(21,007
)
 
$
(67,948
)
 
 
 
 
Basic loss per common share
$
(.18
)
 
$
(.59
)
Diluted loss per common share
$
(.18
)
 
$
(.59
)


















See accompanying Notes to Condensed Consolidated Financial Statements.


2

FOREST OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In Thousands)

 
Three Months Ended
 
March 31,
 
2014
 
2013
Net loss
$
(21,007
)
 
$
(67,948
)
Other comprehensive income:
 

 
 

Defined benefit postretirement plans - amortization of actuarial losses, net of tax
173

 
342

Total other comprehensive income
173

 
342

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




































See accompanying Notes to Condensed Consolidated Financial Statements. 


3

FOREST OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(Unaudited)
(In Thousands)
 
Common Stock
 
Capital Surplus
 
Accumulated Deficit
 
Accumulated
Other
Comprehensive Income (Loss)
 
Total
Shareholders’ Equity
 
Shares
 
Amount
 
 
 
 
Balances at December 31, 2013
119,400

 
$
11,940

 
$
2,554,997

 
$
(2,502,070
)
 
$
(10,398
)
 
$
54,469

Employee stock purchase plan
40

 
4

 
61

 
—

 
—

 
65

Restricted stock issued, net of forfeitures
(216
)
 
(22
)
 
22

 
—

 
—

 
—

Amortization of stock-based compensation
—

 
—

 
1,600

 
—

 
—

 
1,600

Other, net
(125
)
 
(12
)
 
(403
)
 
—

 
—

 
(415
)
Net loss
—

 
—

 
—

 
(21,007
)
 
—

 
(21,007
)
Other comprehensive income
—

 
—

 
—

 
—

 
173

 
173

Balances at March 31, 2014
119,099

 
$
11,910

 
$
2,556,277

 
$
(2,523,077
)
 
$
(10,225
)
 
$
34,885

 

































See accompanying Notes to Condensed Consolidated Financial Statements.


4

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

Three Months Ended
 
March 31,
 
2014
 
2013
Operating activities:
 

 
 

Net loss
$
(21,007
)
 
$
(67,948
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion, and amortization
21,415

 
48,543

Unrealized losses on derivative instruments, net
8,391

 
38,311

Stock-based compensation expense
794

 
3,647

Loss on debt extinguishment
—

 
25,223

Other, net
1,874

 
2,140

Changes in operating assets and liabilities:
 

 
 

Accounts receivable
135

 
265

Other current assets
(1,764
)
 
(1,109
)
Accounts payable and accrued liabilities
(11,533
)
 
(14,697
)
Accrued interest and other
10,541

 
(53
)
Net cash provided by operating activities
8,846

 
34,322

Investing activities:
 

 
 

Capital expenditures for property and equipment:
 

 
 

Exploration, development, and leasehold acquisition costs
(46,380
)
 
(101,665
)
Other property and equipment
(3,520
)
 
(268
)
Proceeds from sales of assets
2,239

 
313,805

Net cash (used) provided by investing activities
(47,661
)
 
211,872

Financing activities:
 

 
 

Proceeds from bank borrowings
—

 
202,000

Repayments of bank borrowings
—

 
(127,000
)
Redemption of senior notes
—

 
(321,315
)
Change in bank overdrafts
21,664

 
590

Other, net
(713
)
 
(300
)
Net cash provided (used) by financing activities
20,951

 
(246,025
)
Net (decrease) increase in cash and cash equivalents
(17,864
)
 
169

Cash and cash equivalents at beginning of period
66,192

 
1,056

Cash and cash equivalents at end of period
$
48,328

 
$
1,225

Cash paid during the period for:
 

 
 

Interest (net of capitalized amounts)
$
8,330

 
$
33,540

Income taxes (net of refunded amounts)
(5,856
)
 
(129
)
Non-cash investing activities:


 


(Decrease) increase in accrued capital expenditures
$
(2,170
)
 
$
26,303

 








See accompanying Notes to Condensed Consolidated Financial Statements.


5

FOREST OIL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1) ORGANIZATION AND BASIS OF PRESENTATION
 
Organization
 
Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. Forest holds assets in several exploration and producing areas in the United States and has exploratory and development interests in two other countries. Unless the context indicates otherwise, the terms “Forest,” the “Company,” “we,” “our,” and “us,” as used in this Quarterly Report on Form 10-Q, refer to Forest Oil Corporation and its subsidiaries.
 
Basis of Presentation
 
The Condensed Consolidated Financial Statements included herein are unaudited and include the accounts of Forest and its consolidated subsidiaries. All intercompany balances and transactions have been eliminated. In the opinion of management, all adjustments, which are of a normal recurring nature, have been made that are necessary for a fair presentation of the financial position of Forest at March 31, 2014, and the results of its operations, its comprehensive income, its cash flows, and changes in its shareholders’ equity for the periods presented. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in the prices of oil, natural gas, and NGLs and the impact the prices have on Forest’s revenues and the fair values of its derivative instruments.
 
In the course of preparing the Condensed Consolidated Financial Statements, management makes various assumptions, judgments, and estimates to determine the reported amounts of assets, liabilities, revenues, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.
 
The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of oil, natural gas, and NGL reserves used in calculating depletion, the amount of future net revenues used in computing the ceiling test limitations, and the amount of future capital costs and abandonment obligations used in such calculations, assessing investments in unproved properties and goodwill for impairment, determining the need for and the amount of deferred tax asset valuation allowances, and estimating fair values of financial instruments, including derivative instruments.

Certain amounts in the prior year financial statements have been reclassified to conform to the 2014 financial statement presentation.

For a more complete understanding of Forest’s operations, financial position, and accounting policies, reference is made to the consolidated financial statements of Forest, and related notes thereto, included in Forest’s Annual Report on Form 10-K for the year ended December 31, 2013, previously filed with the Securities and Exchange Commission (“SEC”).

Subsequent Events

Agreement and Plan of 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. Upon the


6

completion of the combination transaction, Forest shareholders will own approximately 26.5% of the new combined entity and Sabine shareholders will own approximately 73.5%. Consummation of the transaction is subject to approval by Forest shareholders, regulatory approvals, and other customary closing conditions. The combined entity will be known as Sabine Oil & Gas Corporation and be headquartered in Houston.

Going Concern and Management’s Plan

The financial statements included in this Form 10-Q/A have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. Forest previously disclosed in its unreviewed Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, that by year end 2014 the ratio of its total debt to EBITDA may exceed the maximum allowed under its bank credit facility unless it undertakes certain mitigating actions. Absent such actions, a resultant breach of the financial covenant could cause a default under the credit facility, potentially resulting in an acceleration of all amounts outstanding under the credit facility as well as Forest’s senior unsecured notes due 2019 and 2020. As of September 30, 2014, Forest had approximately $13.0 million outstanding under the credit facility and $800.0 million in principal amount outstanding under the notes.
The Company obtained amendments to the credit facility as recently as September 2013 and March 2014 in order to avoid breaching the debt to EBITDA covenant. Forest believes that it could seek, and the lenders under the credit facility would provide, another amendment, or a waiver, of the covenant. Failing an amendment or waiver, Forest believes it could sell assets to avoid breaching the financial covenant. Alternatively, Forest could obtain a new credit facility or other sources of financing. Forest may yet undertake some or all of these actions prior to year end, if necessary, though there is no assurance Forest could complete any such actions as each involves factors that are outside its control. However, inasmuch as Forest has not obtained a waiver or amendment to the credit facility, or pursued any of the other alternatives, there presently exists substantial doubt as to Forest’s ability to continue as a going concern through December 31, 2014.

(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.



7

Diluted earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period, increasing the denominator to include the number of additional common shares that would have been outstanding if the dilutive potential common shares (e.g. stock options, unvested restricted stock, unvested share-settled phantom stock units, and unvested share-settled performance units) had been issued. Additionally, the numerator is also adjusted for certain contracts that provide the issuer or holder with a choice between settlement methods. Diluted earnings per share is computed using the more dilutive of the treasury stock method or the two-class method. Under the treasury stock method, the dilutive effect of potential common shares is computed by assuming common shares are issued for these securities at the beginning of the period, with the assumed proceeds from exercise, which include average unamortized stock-based compensation costs, assumed to be used to purchase common shares at the average market price for the period, and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) included in the denominator of the diluted earnings per share computation. The number of contingently issuable shares pursuant to the outstanding share-settled performance units is included in the denominator of the computation of diluted earnings per share based on the number of shares, if any, that would be issuable if the end of the reporting period were the end of the contingency period and if the result would be dilutive. Under the two-class method, the dilutive effect of non-participating potential common shares is determined and undistributed earnings are reallocated between common shares and participating securities. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three months ended March 31, 2014 and 2013.
 
The following reconciles net loss as reported in the Condensed Consolidated Statements of Operations to net loss used for computing basic and diluted loss per share for the periods presented.
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Net loss
$
(21,007
)
 
$
(67,948
)
Less: net earnings attributable to participating securities
—

 
—

Net loss for basic and diluted loss per share
$
(21,007
)
 
$
(67,948
)

The following reconciles basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the periods presented.
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Weighted average common shares outstanding during the period for basic loss per share
116,838

 
115,655

Dilutive effects of potential common shares
—

 
—

Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted loss per share
116,838

 
115,655


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



8

Compensation Costs
 
The table below sets forth stock-based compensation for the three months ended March 31, 2014 and 2013, and the remaining unamortized amounts and weighted average amortization period as of March 31, 2014.
 
 
Restricted
Stock
 
Performance
Units
 
Phantom
Stock Units
 
Total(1)(2)
 
(In Thousands)
Three Months Ended March 31, 2014:
 

 
 

 
 

 
 

Total stock-based compensation costs
$
1,571

 
$
2

 
$
175

 
$
1,748

Less: stock-based compensation costs capitalized
(799
)
 
(6
)
 
(114
)
 
(919
)
Stock-based compensation costs expensed
$
772

 
$
(4
)
 
$
61

 
$
829

Unamortized stock-based compensation costs(3)
$
6,887

 
$
2,749

 
$
2,078

 
$
11,714

Weighted average amortization period remaining
1.3 years

 
1.7 years

 
1.7 years

 
1.5 years

Three Months Ended March 31, 2013:
 

 
 

 
 

 
 

Total stock-based compensation costs
$
4,235

 
$
1,628

 
$
1,262

 
$
7,125

Less: stock-based compensation costs capitalized
(1,822
)
 
(473
)
 
(669
)
 
(2,964
)
Stock-based compensation costs expensed
$
2,413

 
$
1,155

 
$
593

 
$
4,161

____________________________________________
(1)
Forest also maintains an employee stock purchase plan (which is not included in the table) under which $.03 million and $.1 million of compensation cost was recognized for the three month periods ended March 31, 2014, and 2013, respectively,
(2)
In connection with the divestiture of the South Texas oil and natural gas properties in the first quarter of 2013, Forest incurred $2.0 million ($1.0 million net of capitalized amounts) in stock-based compensation costs due to accelerated vesting of involuntarily terminated employees’ awards. See Note 5 for more information regarding this divestiture.
(3)
The unamortized stock-based compensation costs for liability-based awards are based on the closing price of Forest’s common stock at the reporting period end.
 
Stock Options
 
The following table summarizes stock option activity in the Plans for the three months ended March 31, 2014. 
 
Number of
Options
 
Weighted
Average Exercise
Price
 
Aggregate
Intrinsic Value
(In Thousands)(1)
 
Number of
Options
Exercisable
Outstanding at January 1, 2014
631,206

 
$
17.21

 
$
—

 
631,206

Granted
—

 
—

 
 

 
 

Exercised
—

 
—

 
—

 
 

Cancelled
(171,377
)
 
13.88

 
 

 
 

Outstanding at March 31, 2014
459,829

 
$
18.45

 
$
—

 
459,829

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


9

Restricted Stock, Performance Units, and Phantom Stock Units
 
The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Plans for the three months ended March 31, 2014.
 
 
Restricted Stock
 
Performance Units
 
Phantom Stock Units
 
Number of
Shares(1)
 
Weighted
Average
Grant
Date
Fair
Value
 
Vest Date
Fair
Value
(In
Thousands)
 
Number
of
Units(2)
 
Weighted
Average
Grant
Date
Fair
Value
 
Vest Date
Fair
Value
(In
Thousands)
 
Number
of
Units(3)
 
Weighted
Average
Grant
Date
Fair
Value
 
Vest Date
Fair
Value
(In
Thousands)
Unvested at January 1, 2014
2,790,542

 
$
10.23

 
 

 
1,511,140

 
$
8.48

 
 

 
1,924,819

 
$
6.75

 
 

Awarded
1,000

 
1.82

 
 

 
—

 
—

 
 

 
67,000

 
3.51

 
 

Vested
(349,118
)
 
8.68

 
$
1,166

 
—

 
—

 
$
—

 
(313,287
)
 
7.07

 
$
1,065

Forfeited
(217,173
)
 
9.85

 
 

 
(170,300
)
 
9.33

 
 

 
(139,128
)
 
7.19

 
 

Unvested at March 31, 2014
2,225,251

 
$
10.51

 
 

 
1,340,840

 
$
8.38

 
 

 
1,539,404

 
$
6.51

 
 

 ____________________________________________
(1)
Of the unvested restricted stock as of March 31, 2014, 486,385 shares, which were granted in 2013, vest in one-third increments on each of the first three anniversary dates of the grant. All other unvested shares of restricted stock cliff vest on the third anniversary of the date of grant.
(2)
Of the unvested performance units as of March 31, 2014, 598,500, which were granted in 2013, are cash-based and the remaining unvested performance units are share-based. For both cash- and share-based performance units, the actual settlement amount is dependent upon Forest’s relative total shareholder return in comparison to a specified peer group over a thirty-six month performance period. The cash-based performance units are accounted for as a liability within the Condensed Consolidated Financial Statements.
(3)
All of the unvested phantom stock units as of March 31, 2014 must be settled in cash. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements. All of the phantom stock units that vested during the three months ended March 31, 2014 were settled in cash. Of the unvested phantom stock units as of March 31, 2014, (i) 136,619 were granted in 2011 and 527,785 were granted in 2013 and vest in one-third increments on each of the first three anniversaries of the grant date, (ii) 493,000 were granted in 2013 and 67,000 were granted in 2014 and cliff vest on the third anniversary of the grant date, (iii) and 270,000 were granted in 2012 and 45,000 were granted in 2013 and vest over a four-year period in accordance with the following schedule: (a) 10% on the first anniversary of the grant date; (b) 20% on the second anniversary of the grant date; (c) 30% on the third anniversary of the grant date; and (d) 40% on the fourth anniversary of the grant date.

(4) DEBT
 
The components of debt are as follows:
 
 
March 31, 2014
 
December 31, 2013
 
Principal
 
Unamortized
Premium
 
Total
 
Principal
 
Unamortized
Premium
 
Total
 
(In Thousands)
Credit facility
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

7¼% senior notes due 2019
577,914

 
170

 
578,084

 
577,914

 
178

 
578,092

7½% senior notes due 2020
222,087

 
—

 
222,087

 
222,087

 
—

 
222,087

Total long-term debt
$
800,001

 
$
170

 
$
800,171

 
$
800,001

 
$
178

 
$
800,179



10

Bank Credit Facility
 
As of March 31, 2014, the Company had a $500.0 million credit facility (the “Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A. (the “Administrative Agent”), which matures in June 2016. The size of the Credit Facility may be increased by $300.0 million, to a total of $800.0 million, upon agreement between the applicable lenders and Forest.

On March 31, 2014, the Company entered into the Second Amendment to the Credit Facility (the “Second Amendment”), which was effective as of that date. The Second Amendment amended, among other things, the permitted ratio of total debt to EBITDA and the definition of total debt used in the ratio calculation, and reduced the aggregate lender commitments from $1.5 billion to $500.0 million and the borrowing base, which governs Forest’s availability under the Credit Facility, from $400.0 million to $300.0 million.

The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of Forest’s oil and natural gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. In addition to the scheduled semi-annual redeterminations, Forest and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined. The borrowing base is also subject to automatic adjustments if certain events occur, such as if Forest or any of its Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that Forest or any of its Restricted Subsidiaries may issue to refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if Forest or any of its Restricted Subsidiaries sell oil and natural gas properties having a fair market value, including any economic loss of unwinding any related hedging agreement, in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount equal to either (i) the percentage of the borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by Forest and the required lenders. The February 2013 sale of Forest’s South Texas properties resulted in a $170.0 million reduction to the borrowing base effective February 15, 2013, and the November 2013 sale of Forest’s Texas Panhandle properties resulted in a $300.0 million reduction to the borrowing base effective November 25, 2013. The next scheduled semi-annual redetermination of the borrowing base will occur on or about November 1, 2014. A lowering of the borrowing base could require Forest to repay indebtedness in excess of the borrowing base in order to cover the deficiency.

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

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant. The Second Amendment to the Credit Facility provides that Forest will not permit its ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended to be greater than (i) 5.75 to 1.00 at the end of the calendar quarters ending March 31, 2014, June 30, 2014 and September 30, 2014, (ii) 5.50 to 1.00 at the end of the calendar quarter ending December 31, 2014, (iii) 5.25 to 1.00 at the end of the calendar quarter ending March 31, 2015, (iv) 5.00 to 1.00 at the end of the calendar quarter ending June 30, 2015, (v) 4.75 to 1.00 at the end of the calendar quarter ending September 30, 2015, and (vi) 4.50 to 1.00 at the end of any calendar quarter ending after September 30, 2015. The Second Amendment also amends the definition of total debt such that, among other things, during any period of four fiscal quarters ending on or before September 30, 2015, any cash proceeds from the sale of any property permitted pursuant to the terms and provisions of the loan documents, that are reported on Forest’s consolidated balance sheet on such date are subtracted from total debt.


11

Depending on Forest’s overall level of indebtedness, this covenant may limit Forest’s ability to borrow funds as needed under the Credit Facility. Forest’s ratio of total debt to EBITDA for the four consecutive fiscal quarter period ended March 31, 2014, as calculated in accordance with the Credit Facility, was 4.46.

At March 31, 2014, there were no outstanding borrowings under the Credit Facility and Forest had used the Credit Facility for $2.1 million in letters of credit.

(5) PROPERTY AND EQUIPMENT
 
Full Cost Method of Accounting
 
The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which the Company has operations. During the periods presented, the Company’s primary oil and gas operations were conducted in the United States. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. During the three months ended March 31, 2014 and 2013, Forest capitalized $4.6 million and $12.3 million, respectively, of general and administrative costs (including stock-based compensation). During the three months ended March 31, 2013, Forest capitalized $.2 million of interest costs attributed to unproved properties. No interest costs were capitalized during the three months ended March 31, 2014.

Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, geographic and geologic data obtained relating to the properties, and estimated discounted future net cash flows from the properties. Estimated discounted future net cash flows are based on discounted future net revenues associated with probable and possible reserves, risk adjusted as appropriate. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.
 
The Company performs a ceiling test each quarter on a country-by-country basis under the full cost method of accounting. The ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs.

Forest did not incur a ceiling test write-down during the three months ended March 31, 2014, however, ceiling test write-downs of the United States cost center may be required in future periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenues from estimated production of proved oil and natural gas reserves declines compared to prices used as of March 31, 2014, unproved properties are impaired, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center.



12

Gain or loss is not recognized on the sale of oil and natural gas properties unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and natural gas reserves attributable to a cost center. A significant alteration would not ordinarily be expected to occur for sales involving less than 25% of the reserve quantities of a given cost center. A net gain was recognized on the Panhandle divestiture, which occurred in the fourth quarter of 2013. See “Divestitures” below for more information on the Panhandle divestiture.
 
Depletion of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Company uses its quarter-end reserves estimates to calculate depletion for the current quarter.

Divestitures

Texas Panhandle

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

In connection with the Panhandle divestiture, Forest incurred exit costs consisting of one-time employee termination benefits and other associated costs, as shown in the table below, which includes a reconciliation of the beginning and ending liability balances for these exit costs for the three months ended March 31, 2014.
 
One-Time Employee Termination Benefits
 
Other Associated Costs(1)
 
Total
 
(In Thousands)
Total expected amount(2)
$
4,612

 
$
7,967

 
$
12,579

Total incurred through March 31, 2014(3)
4,554

 
7,967

 
12,521

 
 
 
 
 
 
Liability balance as of December 31, 2013
$
1,095

 
$
5,840

 
$
6,935

Costs incurred(3)
544

 
—

 
544

Costs paid
(1,057
)
 
(5,757
)
 
(6,814
)
Liability balance as of March 31, 2014(4)
$
582

 
$
83

 
$
665

____________________________________________
(1)
Other associated costs consist of financial advisor fees and retention bonuses paid to certain employees.
(2)
Of the $12.6 million total expected costs, the remaining $.1 million will be accrued in the second quarter of 2014 over the remaining retention period of the affected employees.
(3)
Of the $12.5 million costs incurred, (i) $5.5 million was recognized in “General and administrative” expense, $5.0 million during the year ended December 31, 2013 and $.5 million during the quarter ended March 31, 2014, (ii) $5.8 million was recognized in “Other, net” during the year ended December 31, 2013, and (iii) $1.2 million was capitalized in “Oil and natural gas properties” pursuant to the full cost method of accounting, $1.1 million during the year ended December 31, 2013 and the remainder during the quarter ended March 31, 2014.
(4)
The March 31, 2014 estimated liability balance is included in “Accounts payable and accrued liabilities” in the Condensed Consolidated Balance Sheet, and Forest expects it will be paid in the second quarter of 2014.



13

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

South Texas

In January 2013, Forest entered into an agreement to sell all of its oil and natural gas properties located in South Texas, excluding its Eagle Ford Shale oil properties, for $325.0 million in cash. This transaction closed on February 15, 2013, and Forest has received net proceeds of $320.9 million, after customary purchase price adjustments. Forest used the proceeds from this divestiture to redeem the remaining $300.0 million of its 8½% senior notes due 2014. In connection with this divestiture, Forest incurred one-time employee termination benefit costs of $7.5 million ($5.7 million net of capitalization), which are included in “General and administrative” expense in the Condensed Consolidated Statement of Operations for the three months ended March 31, 2013 and were paid in full during 2013.

Asset Retirement Obligations

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

(6) INCOME TAXES
 
The significant differences between Forest’s blended federal and state statutory income tax rate of 36% and its effective income tax rates of 5% and (0.5)% for the three months ended March 31, 2014, and 2013, respectively, were primarily due to changes in the valuation allowance on Forest’s deferred tax assets.

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

Negative evidence considered by Forest included a three-year cumulative book loss driven primarily by the ceiling test write-downs incurred in 2012 and 2013. Positive evidence considered by Forest included forecasted book income in future periods based on expected future oil, natural gas, and NGL production and expected commodity prices based on NYMEX oil and natural gas futures. Based upon the evaluation of what was determined to be relevant evidence, Forest has recorded a valuation allowance against its deferred tax assets.

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



14

(7) FAIR VALUE MEASUREMENTS
 
Forest’s assets and liabilities measured at fair value on a recurring basis at March 31, 2014 and December 31, 2013 are set forth in the table below.
 
 
March 31, 2014
 
December 31, 2013
 
Using Significant Other Observable Inputs
(Level 2)(1)
 
(In Thousands)
Assets:
 

 
 
Derivative instruments(2):
 

 
 
Commodity
$
2,929

 
$
5,592

Liabilities:
 

 
 
Derivative instruments(2):
 

 
 
Commodity
$
10,270

 
$
4,542

____________________________________________
(1)
The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when relevant observable inputs are not available. There were no transfers between levels of the fair value hierarchy during the three months ended March 31, 2014. Forest’s policy is to recognize transfers between levels of the fair value hierarchy as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
(2)
Forest’s currently outstanding derivative assets and liabilities include commodity derivatives (see Note 8 for more information on these instruments). Forest utilizes present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, Forest’s derivative instruments are included within the Level 2 fair value hierarchy.

The fair values and carrying amounts of Forest’s financial instruments are summarized below as of the dates indicated.
 
 
March 31, 2014
 
 
 
 
 
Fair Value Measurements
 
Carrying
Amount
 
Total Fair
Value(1)
 
Using Quoted Prices in
Active Markets for Identical Liabilities
(Level 1)
 
Using Significant Other
Observable Inputs
(Level 2)
 
(In Thousands)
Assets:
 

 
 

 
 

 
 

Derivative instruments
$
2,929

 
$
2,929

 
$
—

 
$
2,929

Liabilities:
 

 
 

 
 

 
 

Derivative instruments
10,270

 
10,270

 
—

 
10,270

7¼% senior notes due 2019
578,084

 
507,842

 
507,842

 
—

7½% senior notes due 2020
222,087

 
194,466

 
194,466

 
—

__________________________________________
(1)
Forest used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on quoted market prices. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 8 for more information on the derivative instruments.



15

 
December 31, 2013
 
 
 
 
 
Fair Value Measurements
 
Carrying
Amount
 
Total Fair
Value(1)
 
Using Quoted Prices in
Active Markets for Identical Liabilities
(Level 1)
 
Using Significant Other
Observable Inputs
(Level 2)
 
(In Thousands)
Assets:
 

 
 

 
 
 
 
Derivative instruments
$
5,592

 
$
5,592

 
$
—

 
$
5,592

Liabilities:
 

 
 

 
 
 
 
Derivative instruments
4,542

 
4,542

 
—

 
4,542

7¼% senior notes due 2019
578,092

 
568,147

 
568,147

 
—

7½% senior notes due 2020
222,087

 
224,030

 
224,030

 
—

__________________________________________
(1)
Forest used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on quoted market prices. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 8 for more information on the derivative instruments.
   
(8) DERIVATIVE INSTRUMENTS
 
Commodity Derivatives
 
Forest periodically enters into commodity derivative instruments in order to moderate the effects of wide fluctuations in commodity prices on Forest’s cash flow and to manage its exposure to commodity price risk. Forest’s commodity derivative instruments generally serve as effective economic hedges of commodity price exposure; however, Forest has elected not to designate its derivatives as hedging instruments for accounting purposes. As such, Forest recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the line item “Realized and unrealized losses on derivative instruments, net” in the Condensed Consolidated Statement of Operations.
 
The table below sets forth Forest’s outstanding commodity swaps as of March 31, 2014.
 
Commodity Swaps
 
 
Natural Gas
(NYMEX HH)
 
Oil
(NYMEX WTI)
Remaining Swap Term
 
Bbtu
Per Day
 
Weighted
Average
Hedged Price
per MMBtu
 
Barrels
Per Day
 
Weighted
Average
Hedged Price
per Bbl
April 2014 - December 2014
 
70

 
$
4.38

 
3,500

 
$
95.34

Calendar 2015
 
50

 
4.21

 
1,000

 
89.25


The table below sets forth Forest’s outstanding commodity collars as of March 31, 2014.
Commodity Collars
 
 
Natural Gas
(NYMEX HH)
Collar Term
 
Bbtu
Per Day
 
Hedged Floor and Ceiling Price
per MMBtu
January 2015 - March 2015
 
20

 
$ 4.50/5.31
Calendar 2015
 
10

 
        4.10/4.30


16

In connection with several of its natural gas and oil swaps, Forest granted option instruments (swaptions and puts) to the swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas and oil swaps. Under the terms of the swaption agreements, the counterparties have the option to enter into future swaps with Forest. The swaptions may not be exercised until their expiration dates. Under the terms of the put agreements, the counterparties have the option to put specified quantities of oil to Forest at specified prices. The puts may be exercised monthly by the counterparties. The table below sets forth the outstanding options as of March 31, 2014.
 
Commodity Options
 
 
 
 
Natural Gas (NYMEX HH)
 
Oil (NYMEX WTI)
Underlying Term
 
Option Expiration
 
Underlying
Bbtu
Per Day
 
Underlying
Hedged Price per
MMBtu
 
Underlying
Barrels Per Day
 
Underlying
Hedged Price
per Bbl
Gas Swaptions:
 
 
 
 
 
 
 
 
 
 
Calendar 2016
 
December 2014
 
10

 
$
4.18

 
—

 
$
—

Oil Swaptions:
 
 
 
 
 
 
 
 
 
 
Calendar 2015
 
December 2014
 
—

 
—

 
3,000

 
100.00

Calendar 2015
 
December 2014
 
—

 
—

 
1,000

 
106.00

Calendar 2015
 
December 2014
 
—

 
—

 
1,000

 
99.00

Calendar 2016
 
December 2015
 
—

 
—

 
1,000

 
98.00

Oil Put Options:
 
 
 
 
 
 
 
 
 
 
Monthly Calendar 2014
 
Monthly Calendar 2014
 
—

 
—

 
2,000

 
70.00


Fair Value and Gains and Losses
 
The table below summarizes the location and fair value amounts of Forest’s derivative instruments reported in the Condensed Consolidated Balance Sheets as of the dates indicated. These derivative instruments are not designated as hedging instruments for accounting purposes. For financial reporting purposes, Forest does not offset asset and liability fair value amounts recognized for derivative instruments with the same counterparty under its master netting arrangements. See “Credit Risk” below for more information regarding Forest’s master netting arrangements and gross and net presentation of derivative instruments. See also Note 7 for more information on the fair values of Forest’s derivative instruments.
 
 
March 31, 2014
 
December 31, 2013
 
(In Thousands)
Current assets:
 

 
 

Derivative instruments:
 

 
 

Commodity
$
713

 
$
5,192

Long-term assets:
 
 
 
Derivative instruments:
 
 
 
Commodity
$
2,216

 
$
400

Current liabilities:
 

 
 

Derivative instruments:
 

 
 

Commodity
$
9,598

 
$
4,542

Long-term liabilities:
 
 
 
Derivative instruments:
 
 
 
Commodity
$
672

 
$
—



17

The table below summarizes the amount of derivative instrument gains and losses reported in the Condensed Consolidated Statements of Operations as realized and unrealized (gains) losses on derivative instruments, net, for the periods indicated. Realized gains and losses represent cash settlements on derivative instruments and unrealized gains and losses represent changes in fair value of derivative instruments. These derivative instruments are not designated as hedging instruments for accounting purposes.
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Commodity derivatives:
 

 
 

Realized losses (gains)
$
4,460

 
$
(9,649
)
Unrealized losses
8,391

 
35,161

Interest rate derivatives:
 

 
 

Realized gains
—

 
(3,082
)
Unrealized losses
—

 
3,150

Realized and unrealized losses on derivative instruments, net
$
12,851

 
$
25,580

 
Due to the volatility of oil and natural gas prices, the estimated fair values of Forest’s commodity derivative instruments are subject to large fluctuations from period to period. Forest has experienced the effects of these commodity price fluctuations and expects that volatility in commodity prices will continue.
 
Credit Risk
 
Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. (“ISDA”) Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes, with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties’ requirements and the specific types of derivatives to be transacted. As of March 31, 2014, all but one of Forest’s derivative counterparties are lenders, or affiliates of lenders, under the Credit Facility. The terms of the Credit Facility provide that any security granted by Forest thereunder shall also extend to and be available to those lenders that are counterparties to derivative transactions. None of these counterparties requires collateral beyond that already pledged under the Credit Facility. The remaining counterparty, a purchaser of Forest’s natural gas production, generally owes money to Forest and therefore does not require collateral under the ISDA Master Agreement and Schedule it has executed with Forest.

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

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


18

generally contain netting provisions whereby if on any date amounts would otherwise be payable by each party to the other, then on such date, the party that owes the larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party’s obligations. These provisions generally apply to all derivative transactions, or all derivative transactions of the same type (e.g., commodity, interest rate, etc.), with the particular counterparty. If all counterparties failed, Forest would be exposed to a risk of loss equal to this net amount owed to Forest, the fair value of which was $.3 million at March 31, 2014. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net obligations due to it under the derivative agreements. At March 31, 2014, Forest owed a net derivative liability to its counterparties, the fair value of which was $7.7 million. In the absence of netting provisions, at March 31, 2014, Forest would be exposed to a risk of loss of $2.9 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $10.3 million.
 
For financial reporting purposes, Forest has elected to not offset asset and liability fair value amounts recognized for derivative instruments with the same counterparty under its master netting arrangements, although such derivative instruments are subject to enforceable master netting arrangements. The following tables disclose information regarding the potential effect of netting arrangements on Forest’s Condensed Consolidated Balance Sheets as of the dates indicated.

 
Derivative Assets
 
March 31, 2014
 
December 31, 2013
 
(In Thousands)
Gross amounts of recognized assets
$
2,929

 
$
5,592

Gross amounts offset in the balance sheet
—

 
—

Net amounts of assets presented in the balance sheet
2,929

 
5,592

Gross amounts not offset in the balance sheet:
 
 
 
Derivative instruments
(2,582
)
 
(1,049
)
Cash collateral received
—

 
—

Net amount
$
347

 
$
4,543


 
Derivative Liabilities
 
March 31, 2014
 
December 31, 2013
 
(In Thousands)
Gross amounts of recognized liabilities
$
10,270

 
$
4,542

Gross amounts offset in the balance sheet
—

 
—

Net amounts of liabilities presented in the balance sheet
10,270

 
4,542

Gross amounts not offset in the balance sheet:
 
 
 
Derivative instruments
(2,582
)
 
(1,049
)
Cash collateral pledged
—

 
—

Net amount
$
7,688

 
$
3,493


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



19

(9) COSTS, EXPENSES, AND OTHER
 
The table below sets forth the components of “Other, net” in the Condensed Consolidated Statements of Operations for the periods indicated.
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Accretion of asset retirement obligations
$
513

 
$
1,244

Write-off of debt issuance costs
3,323

 
—

Loss on debt extinguishment
—

 
25,223

Loss on asset disposition, net
794

 
—

Rig stacking/lease termination
5,184

 
3,038

Other, net
(1,166
)
 
(685
)
 
$
8,648

 
$
28,820


Accretion of Asset Retirement Obligations

Accretion of asset retirement obligations is the expense recognized to increase the carrying amount of the liability associated with Forest’s asset retirement obligations as a result of the passage of time. Forest’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and natural gas properties.

Write-off of Debt Issuance Costs

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

Loss on Debt Extinguishment

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

Loss on Asset Disposition, Net

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

Rig Stacking/Lease Termination

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


20

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

(10) COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that, under generally accepted accounting principles, are reported as separate components of shareholders’ equity instead of net earnings (loss). Forest’s other comprehensive income during the three months ended March 31, 2014 consists of actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost, which is included in the line item “General and administrative” in the Condensed Consolidated Statements of Operations.

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

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

 
$
—

 
$
173

Other comprehensive income
$
173

 
$
—

(1) 
$
173

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

The change in the accumulated balance of other comprehensive income (loss) during the three months ended March 31, 2014 is as follows:
 
Accumulated
Other
Comprehensive
Income (Loss)(1)
 
(In Thousands)
Defined benefit postretirement plans
 
Balance at December 31, 2013
$
(10,398
)
 
 
Amounts reclassified from accumulated other comprehensive loss
173

Other comprehensive income
173

 
 
Balance at March 31, 2014
$
(10,225
)
____________________________________
(1)
All amounts are net of tax.


21

(11) NEW ACCOUNTING STANDARDS

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

Item 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
OVERVIEW
 
All expectations, forecasts, assumptions, and beliefs about our future financial results, condition, operations, strategic plans, and performance are forward-looking statements, as described in more detail under the heading “Forward-Looking Statements” below. Our actual results may differ materially because of a number of risks and uncertainties. Historical statements made herein are accurate only as of the date of filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”), and may be relied upon only as of that date. The following discussion and analysis should be read in conjunction with Forest’s Condensed Consolidated Financial Statements and the Notes thereto, the information included or incorporated by reference under the headings “Forward-Looking Statements” and “Risk Factors” below, and the information included or incorporated by reference in Forest’s 2013 Annual Report on Form 10-K under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Unless the context indicates otherwise, all references in this document to “Forest,” “the Company,” “we,” “our,” “ours,” and “us” refer to Forest Oil Corporation and its consolidated subsidiaries.
 
Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. We currently conduct our operations in one reportable geographical segment - the United States. Our core operational areas are in the Eagle Ford in South Texas and the Ark-La-Tex region in Texas, Louisiana, and Arkansas.

Recent Events

In October 2013, we entered into an agreement to sell all of our oil and natural gas properties located in the Texas Panhandle for $1 billion in cash. This transaction closed in November 2013 and we have received net cash proceeds of $965 million through March 31, 2014, after customary purchase price adjustments. As of March 31, 2014, $33 million remains in escrow, which we may receive as consents-to-assign are received and title curative work is completed. Of the $33 million escrow balance, $10 million supports post-closing indemnities that we may owe to the buyer under the terms of the purchase and sale agreement. We will receive any of the $10 million remaining in escrow at the one-year anniversary of the closing. In January 2013, we entered into an agreement to sell all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford oil properties, for $325 million in cash. This transaction closed in February 2013 and we have received net proceeds of $321 million, after customary purchase price adjustments. We used the proceeds from these property divestitures to reduce our debt. These property divestitures affect the comparability of the results of our operations between the three months ended March 31, 2014 and the three months ended March 31, 2013 presented herein.



22

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

RESULTS OF OPERATIONS

For the three months ended March 31, 2014, we recognized a net loss of $21 million compared to a net loss of $68 million for the three months ended March 31, 2013. Adjusted EBITDA, which is a measure used by management, securities analysts, and investors that consists of net loss before interest expense, income taxes, depreciation, depletion, and amortization, as well as other items including unrealized gains and losses on derivative instruments, was $35 million for the three months ended March 31, 2014 and $94 million for the three months ended March 31, 2013. The $60 million decrease was primarily due to the property divestitures referenced above under “Recent Events.” Adjusted EBITDA is a performance measure not calculated in accordance with generally accepted accounting principles (“GAAP”). See “Reconciliation of Non-GAAP Measure” at the end of this Item 2 for a reconciliation of Adjusted EBITDA to our reported net loss, the most directly comparable financial measure calculated and presented in accordance with GAAP.

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

Oil, Natural Gas, and Natural Gas Liquids Volumes, Revenues, and Prices
 
Oil, natural gas, and natural gas liquids sales volumes, revenues, and per unit price realizations for the three months ended March 31, 2014 and 2013 are set forth in the table below.

 
Three Months Ended
 
March 31,
 
2014

2013
Sales volumes:
 

 
 

Oil (MBbls)
326

 
559

Natural gas (MMcf)
6,438

 
14,332

NGLs (MBbls)
178

 
698

Totals (MMcfe)
9,462

 
21,874

Revenues (in thousands):
 
 
 
Oil
$
30,332

 
$
53,962

Natural gas
28,171

 
42,658

NGLs
5,954

 
21,422

Totals
$
64,457

 
$
118,042

Per unit price realizations:
 

 
 

Oil ($/Bbl)
$
93.04

 
$
96.53

Natural gas ($/Mcf)
4.38

 
2.98

NGLs ($/Bbl)
33.45

 
30.69

Totals ($/Mcfe)
$
6.81

 
$
5.40


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 table below distinguishes 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


23

“Divested properties”) and those oil and natural gas properties that we continued to own as of March 31, 2014 (the “Retained properties”).
 
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
March 31,
 
$
Change
 
Three Months Ended
March 31,
 
Volume Change
 
Three Months Ended
March 31,
 
$ Change (1)
 
Volumes (2)
 
Prices (3)
 
Total
 
2014
 
2013
 
 
2014
 
2013
 
 
2014
 
2013
 
 
 
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
(In Thousands)
Oil
 
 
 
 
 
 
MBbls
 
$/Bbl
 
 
 
 
 
 
Retained properties
$
30,332

 
$
27,225

 
$
3,107

 
326

 
262

 
64

 
$
93.04

 
$
103.91

 
$
(10.87
)
 
$
6,650

 
$
(3,543
)
 
$
3,107

Divested properties
—

 
26,737

 
(26,737
)
 
—

 
297

 
(297
)
 
—

 
90.02

 
(90.02
)
 
(26,737
)
 
—

 
(26,737
)
 
$
30,332

 
$
53,962

 
$
(23,630
)
 
326

 
559

 
(233
)
 
$
93.04

 
$
96.53

 
$
(3.49
)
 
$
(22,492
)
 
$
(1,138
)
 
$
(23,630
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
 
 
 
 
 
MMcf
 
$/Mcf
 
 
 
 
 
 
Retained properties
$
28,171

 
$
23,888

 
$
4,283

 
6,438

 
7,666

 
(1,228
)
 
$
4.38

 
$
3.12

 
$
1.26

 
$
(3,827
)
 
$
8,110

 
$
4,283

Divested properties
—

 
18,770

 
(18,770
)
 
—

 
6,666

 
(6,666
)
 
—

 
2.82

 
(2.82
)
 
(18,770
)
 
—

 
(18,770
)
 
$
28,171

 
$
42,658

 
$
(14,487
)
 
6,438

 
14,332

 
(7,894
)
 
$
4.38

 
$
2.98

 
$
1.40

 
$
(23,496
)
 
$
9,009

 
$
(14,487
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NGLs
 
 
 
 
 
 
MBbls
 
$/Bbl
 
 
 
 
 
 
Retained properties
$
5,954

 
$
5,599

 
$
355

 
178

 
174

 
4

 
$
33.45

 
$
32.18

 
$
1.27

 
$
129

 
$
226

 
$
355

Divested properties
—

 
15,823

 
(15,823
)
 
—

 
524

 
(524
)
 
—

 
30.20

 
(30.20
)
 
(15,823
)
 
—

 
(15,823
)
 
$
5,954

 
$
21,422

 
$
(15,468
)
 
178

 
698

 
(520
)
 
$
33.45

 
$
30.69

 
$
2.76

 
$
(15,959
)
 
$
491

 
$
(15,468
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
MMcfe
 
$/Mcfe
 
 
 
 
 
 
Retained properties
$
64,457

 
$
56,712

 
$
7,745

 
9,462

 
10,282

 
(820
)
 
$
6.81

 
$
5.52

 
$
1.30

 
$
(4,523
)
 
$
12,268

 
$
7,745

Divested properties
—

 
61,330

 
(61,330
)
 
—

 
11,592

 
(11,592
)
 
—

 
5.29

 
(5.29
)
 
(61,330
)
 
—

 
(61,330
)
 
$
64,457

 
$
118,042

 
$
(53,585
)
 
9,462

 
21,874

 
(12,412
)
 
$
6.81

 
$
5.40

 
$
1.42

 
$
(66,981
)
 
$
13,396

 
$
(53,585
)
____________________________________________
(1)
Certain amounts may not recalculate due to rounding.
(2)
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 March 31, 2013 and (ii) the change in volumes between the three months ended March 31, 2013 and the three months ended March 31, 2014. Certain amounts do not recalculate or foot due to rounding.
(3)
The change in revenues attributable to the change in prices is calculated as the product of (i) the volumes for the three months ended March 31, 2014 and (ii) the change in the per unit price realization between the three months ended March 31, 2013 and the three months ended March 31, 2014. Certain amounts do not recalculate or foot due to rounding.

Our equivalent sales volumes were 9.5 Bcfe for the three months ended March 31, 2014 and 21.9 Bcfe for the three months ended March 31, 2013. Of the 12.4 Bcfe decrease in equivalent sales volumes in the first quarter of 2014 compared to the first quarter of 2013, approximately 11.6 Bcfe, or 93%, was due to divestitures of producing oil and natural gas properties in South Texas and the Texas Panhandle, which occurred in February 2013 and November 2013, respectively. The remaining .8 Bcfe decrease is due to a 1.2 Bcfe decrease in natural gas production in the Ark-La-Tex region which was partially offset by an increase in oil production primarily in the Eagle Ford. Our liquids sales volumes have increased 16% to 32% of total equivalent sales volumes during the first quarter 2014 as compared to 25% in the first quarter 2013, excluding the effects of property divestitures.

Revenues from oil, natural gas, and NGLs were $64 million in the first quarter of 2014 compared to $118 million in the first quarter of 2013. Of the $54 million decrease, approximately $61 million was a result of the property divestitures discussed above. This decrease was partially offset by a 23% increase in the per unit price realization on production from the properties we’ve retained, from $5.52 per Mcfe in the first quarter of 2013 to $6.81 per Mcfe in the first quarter of 2014.

The revenues and per unit price realizations reflected in the table above exclude the effects of commodity derivative instruments because we have elected not to designate our derivative instruments as cash flow hedges. See


24

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

Production Expense
 
The table below sets forth the detail of production expense for the periods indicated.
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands, Except Per Mcfe Data)
Production expense:
 

 
 

Lease operating expenses
$
14,510

 
$
21,204

Production and property taxes
3,225

 
2,216

Transportation and processing costs
2,515

 
3,280

Production expense
$
20,250

 
$
26,700

Production expense per Mcfe:
 

 
 

Lease operating expenses
$
1.53

 
$
.97

Production and property taxes
.34

 
.10

Transportation and processing costs
.27

 
.15

Production expense per Mcfe
$
2.14

 
$
1.22


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 table below distinguishes 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 March 31, 2014 (the “Retained properties”).



25

 
Production Expense
 
Production Expense per Mcfe
 
Three Months Ended
March 31,
 
$ Change
 
Three Months Ended
March 31,
 
$ Change
 
2014
 
2013
 
 
2014
 
2013
 
Lease operating expenses
(In Thousands)
 
$/Mcfe
Retained properties
$
14,510

 
$
10,688

 
$
3,822

 
$
1.53

 
$
1.04

 
$
.49

Divested properties
—

 
10,516

 
(10,516
)
 
—

 
.91

 
(.91
)
 
$
14,510

 
$
21,204

 
$
(6,694
)
 
$
1.53

 
$
.97

 
$
.56

Production and property taxes
 
 
 
 
 
 
 
 
 
 
 
Retained properties
$
3,225

 
$
2,526

 
$
699

 
$
.34

 
$
.25

 
$
.09

Divested properties
—

 
(310
)
 
310

 
—

 
(.03
)
 
.03

 
$
3,225

 
$
2,216

 
$
1,009

 
$
.34

 
$
.10

 
$
.24

Transportation and processing costs
 
 
 
 
 
 
 
 
 
 
 
Retained properties
$
2,515

 
$
3,020

 
$
(505
)
 
$
.27

 
$
.29

 
$
(.02
)
Divested properties
—

 
260

 
(260
)
 
—

 
.02

 
(.02
)
 
$
2,515

 
$
3,280

 
$
(765
)
 
$
.27

 
$
.15

 
$
.12

Total
 
 
 
 
 
 
 
 
 
 
 
Retained properties
$
20,250

 
$
16,234

 
$
4,016

 
$
2.14

 
$
1.58

 
$
.56

Divested properties
—

 
10,466

 
(10,466
)
 
—

 
.90

 
(.90
)
 
$
20,250

 
$
26,700

 
$
(6,450
)
 
$
2.14

 
$
1.22

 
$
.92


Lease Operating Expenses
 
Lease operating expenses in the first quarter of 2014 were $15 million, or $1.53 per Mcfe, compared to $21 million, or $.97 per Mcfe, in the first quarter of 2013. Lease operating expenses decreased $7 million in the three month period ended March 31, 2014 compared to the corresponding period in 2013 due primarily to property divestitures that occurred in February 2013 and November 2013. The lease operating costs incurred for these divested properties was $11 million in the first quarter of 2013. The net increase in lease operating expenses of $4 million between the two periods attributable to the Retained properties was primarily due to increased costs related to our oil production, namely saltwater disposal and chemical treatment costs, which increased approximately $2 million. Based on the energy-equivalent ratio of six Mcf of natural gas to one barrel of oil, oil production typically has higher per-unit lease operating costs than does natural gas production. However, because the market price of oil relative to natural gas is currently well in excess of the standard energy equivalent six-to-one ratio, the increase in lease operating expense associated with an increase in oil production is typically more than offset by the additional revenues realized from oil sales. Additionally, workovers and overhead also increased by approximately $1 million each in the first quarter of 2014 as compared to the first quarter of 2013.
 
Production and Property Taxes
 
Production and property taxes, consisting primarily of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 5.0% and 1.9% of oil, natural gas, and NGL revenues for the three-month periods ended March 31, 2014 and 2013, respectively. The increase in the percentage from the first quarter of 2013 to the first quarter of 2014 was due to the approval of reduced severance tax rates on several wells in the Texas Panhandle during the first quarter of 2013 for which refunds were accrued to recover the severance taxes paid on these wells prior to the approval of the reduced rate. Excluding the production and property taxes and revenues related to the South Texas and Texas Panhandle divestitures, production and property taxes were 4.5% of oil, natural gas, and NGL revenues for the three months ended March 31, 2013. Normal fluctuations also occur in this percentage between periods based upon changes in tax rates and changes in the assessed values of oil and gas properties and equipment for purposes of ad valorem taxes.
 


26

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

General and Administrative Expense
 
The table below sets forth the components of general and administrative expense for the periods indicated.
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Stock-based compensation costs
$
1,774

 
$
7,224

Stock-based compensation costs capitalized
(919
)
 
(2,964
)
 
855

 
4,260

 
 
 
 
Labor costs(1)
6,216

 
19,896

Other general and administrative costs
4,808

 
5,192

Other general and administrative costs capitalized
(3,639
)
 
(9,334
)
 
7,385

 
15,754

 
 
 
 
General and administrative expense
$
8,240

 
$
20,014

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

General and administrative expense was $8 million in the first quarter of 2014 compared to $20 million in the first quarter of 2013. For the first quarter of 2014, labor costs include $1 million ($1 million net of capitalized amounts) in employee-related asset divestiture costs related to the Texas Panhandle divestiture and the resulting reduction in employee headcount, most of which occurred in the fourth quarter of 2013, with some employees staying throughout the first quarter of 2014 during a transition period post-divestiture. For the first quarter of 2013, labor costs include $8 million ($6 million net of capitalized amounts) in employee-related asset divestiture costs related to the South Texas divestiture and the resulting reduction in employee headcount. Labor costs also decreased in the first quarter of 2014 as compared to the first quarter of 2013 by approximately $6 million attributable to decreased salaries, wages, other cash incentives, and burden due to decreased employee headcount.

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

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


27


Depreciation, Depletion, and Amortization

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

 
Three Months Ended March 31,
 
2014
 
2013
 
In Thousands
 
$/Mcfe
 
In Thousands
 
$/Mcfe
Depletion
$
20,264

 
$
2.14

 
$
47,538

 
$
2.17

Depreciation
1,151

 
.12

 
1,005

 
.05

Depreciation, depletion, and amortization
$
21,415

 
$
2.26

 
$
48,543

 
$
2.22


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

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

Interest Expense
 
The table below sets forth interest expense for the periods indicated.
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Credit facility(1)
$
1,027

 
$
1,627

7¼% senior notes due 2019(1)
10,657

 
18,442

7½% senior notes due 2020(1)
4,299

 
9,673

8½% senior notes due 2014(1)
—

 
6,277

Other
28

 
300

Interest costs capitalized
—

 
(191
)
Interest expense
$
16,011

 
$
36,128

 ___________________________________________
(1)
Interest expense amounts include interest on the principal or borrowings outstanding, amortization of debt issuance costs, amortization of discounts and premiums, and credit facility commitment, letter of credit, and other fees, all as applicable.
 
Interest expense was $16 million and $36 million for the three months ended March 31, 2014 and 2013, respectively. Interest expense decreased $20 million in the first quarter 2014 as compared to the first quarter 2013. This decrease was comprised of the following: (i) $6 million due to the redemption of the $300 million of 8½% senior notes in March 2013, (ii) $13 million due to the redemption of $700 million of 7¼% senior notes and 7½% senior notes in November 2013, and (iii) $1 million due to there being no borrowings outstanding under our credit facility and a decreased credit facility commitment amount, upon which commitment fees are based, during the three months ended March 31, 2014 as compared to the three months ended March 31, 2013. Interest costs capitalized relate to our investments in significant unproved acreage positions that are under development. See “Liquidity and Capital Resources—Bank Credit Facility” below for more information regarding our credit facility.


28

Realized and Unrealized Gains and Losses on Derivative Instruments

The table below sets forth realized and unrealized gains and losses on derivative instruments recognized under “Costs, expenses, and other” in our Condensed Consolidated Statements of Operations for the periods indicated. Realized gains and losses represent cash settlements on derivative instruments and unrealized gains and losses represent changes in fair value of derivative instruments. Realized and unrealized gains and losses on derivative instruments vary from period to period based on the specific terms of the derivative instruments to which we are a party during the period and based on the third-party indices’ settlement prices during the period. See Note 7 and Note 8 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Realized losses (gains) on derivative instruments, net:
 

 
 

Oil
$
1,032

 
$
(428
)
Natural gas
3,428

 
(9,221
)
Interest
—

 
(3,082
)
Subtotal realized losses (gains) on derivative instruments, net
4,460

 
(12,731
)
Unrealized losses (gains) on derivative instruments, net:
 

 
 

Oil
2,037

 
(308
)
Natural gas
6,354

 
35,469

Interest
—

 
3,150

Subtotal unrealized losses on derivative instruments, net
8,391

 
38,311

Realized and unrealized losses on derivative instruments, net
$
12,851

 
$
25,580


Other, Net
 
The table below sets forth the components of “Other, net” for the periods indicated.
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Accretion of asset retirement obligations
$
513

 
$
1,244

Write-off of debt issuance costs
3,323

 
—

Loss on debt extinguishment
—

 
25,223

Loss on asset disposition, net
794

 
—

Rig stacking/lease termination
5,184

 
3,038

Other, net
(1,166
)
 
(685
)
 
$
8,648

 
$
28,820

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



29

Income Tax
 
The table below sets forth total income tax and the effective income tax rates for the periods indicated.
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands, Except Percentages)
Current income tax
$
(1,214
)
 
$
337

Deferred income tax
—

 
—

Total income tax (benefit) expense
$
(1,214
)
 
$
337

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

LIQUIDITY AND CAPITAL RESOURCES

Our exploration, development, and acquisition activities require us to make significant operating and capital expenditures (see “Capital Expenditures”). Historically, we have used cash flow from operations and our bank credit facility as our primary sources of liquidity. To fund large transactions, such as acquisitions and debt refinancing transactions, we have looked to the private and public capital markets as another source of financing and, as market conditions have permitted, we have engaged in asset monetization transactions.
 
Changes in the market prices for oil, natural gas, and NGLs directly impact our level of cash flow generated from operations. We employ a commodity hedging strategy in an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of May 2, 2014, we had hedged, via commodity swaps and collars, approximately 33 Bcfe of our total projected 2014 production and approximately 26 Bcfe of our total projected 2015 production, excluding the volumes underlying outstanding unexercised commodity swaptions and oil put options. This level of hedging will provide a measure of certainty with respect to the cash flow that we will receive for a portion of our future production. However, these hedging activities may result in reduced income or even financial losses to us. In the future, we may increase or decrease our hedging positions. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” below for more information on our derivative instruments.
 
As noted above, the other primary source of liquidity is our credit facility, which currently has a borrowing base of $300 million. The borrowing base is subject to redetermination from time to time as discussed below under “Bank Credit Facility.” This facility is used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facility is secured by a portion of our assets and matures in June 2016. The credit facility contains a covenant that we will not permit our ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended to be greater than 5.75 to 1.00 as of March 31, 2014. Future periods have differing limitations as discussed below under “Bank Credit Facility.” Depending on our overall level of indebtedness, this covenant may limit our ability to borrow funds as needed under our credit facility. Our ratio of total debt to EBITDA for the four consecutive fiscal quarter period ended March 31, 2014, as calculated in accordance with the credit facility, was 4.46. We had no borrowings outstanding under the credit facility as of March 31, 2014 and May 2, 2014. The covenant described above would currently prevent us from borrowing the full amount of our remaining borrowing base. See “Bank Credit Facility” below for further details regarding the credit facility.
 


30

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

We also have engaged in asset dispositions and joint ventures as a means of generating additional cash to fund more attractive capital projects and to enhance our financial flexibility. For example, in November 2012, we sold all of our oil and natural gas properties located in South Louisiana for net proceeds of $211 million. Additionally, in February 2013 we sold all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford oil properties, for net proceeds of $321 million, which we used in March 2013 to redeem the remaining $300 million in principal amount of 8½% senior notes due 2014. In November 2013, we sold all of our oil and natural gas properties located in the Texas Panhandle for net proceeds to date of $965 million, which we used in November 2013 to redeem $700 million of 7¼% senior notes due 2019 and 7½% senior notes due 2020, and to pay off the outstanding balance on our credit facility. In addition, we have entered into an agreement with a third-party pursuant to which the third-party is funding a portion of the drilling and other development costs relating to certain Eagle Ford acreage in exchange for a 50% working interest in that acreage.

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

See “Going Concern Subsequent Event” below for updated disclosure on the status of our compliance with the total debt to EBITDA covenant in the Credit Facility and its effect on our ability to continue as a going concern.

Bank Credit Facility
 
On June 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the ‘‘Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A. (the “Administrative Agent”), which, as of March 31, 2014, consists of a $500 million credit facility maturing in June 2016. The size of the Credit Facility may be increased by $300 million, to a total of $800 million, upon agreement between us and the applicable lenders. On March 31, 2014, we entered into the Second Amendment to the Credit Facility (the “Second Amendment”), which was effective as of that date. The Second Amendment amended, among other things, the permitted ratio of total debt to EBITDA and the definition of total debt used in the ratio calculation, and reduced the aggregate lender commitments from $1.5 billion to $500 million and the borrowing base, which governs our availability under the Credit Facility, from $400 million to $300 million.
 
The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil and natural gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. A reduction of the borrowing base could require us to repay indebtedness in excess of the borrowing base in order to cover the deficiency. The next scheduled semi-annual redetermination of the borrowing base will occur on or about November 1, 2014. In addition to the scheduled semi-annual redeterminations, we and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined.

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


31

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

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



32

At March 31, 2014 and May 2, 2014, there were no outstanding borrowings under the Credit Facility. We had used the Credit Facility for $2 million and $3 million in letters of credit at March 31, 2014 and May 2, 2014, respectively. At May 2, 2014, the unused borrowing amount under the Credit Facility was $297 million. However, based on the ratio of total debt to EBITDA discussed above, our borrowing utilization of the Credit Facility is currently limited to approximately $218 million.

Of the $500 million total nominal amount under the Credit Facility, JPMorgan and ten other banks hold approximately 68% of the total commitments. With respect to the other 32% of the total commitments, no single lender holds more than 3.3% of the total commitments. Commitment fees accrue on the amount of unutilized borrowing base. If borrowing base utilization is greater than 50%, commitment fees are 50 basis points of the unutilized amount, and if borrowing base utilization is 50% or less, commitment fees are 35 basis points of the unutilized amount.

We engage in other transactions with a number of the lenders under the Credit Facility. Such lenders or their affiliates may serve as underwriters or initial purchasers of our debt and equity securities, directly purchase our production, serve as counterparties to our commodity and interest rate derivative agreements, or from time to time act as investment banking advisers with respect to our asset acquisitions and divestitures. As of May 2, 2014, all but one of our derivative instrument counterparties are lenders, or their affiliates, under our Credit Facility. Our obligations under our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our Credit Facility. See Item 3, ‘‘Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk’’ below for additional details concerning our derivative instruments.

Going Concern Subsequent Event

The financial statements included in this Form 10-Q/A have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. We previously disclosed in our unreviewed Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 that by year end 2014 the ratio of our total debt to EBITDA may exceed the maximum allowed under our Credit Facility unless we undertake certain mitigating actions. Absent such actions, a resultant breach of the financial covenant could cause a default under the Credit Facility, potentially resulting in an acceleration of all amounts outstanding under the Credit Facility as well as our senior unsecured notes due 2019 and 2020. As of September 30, 2014, we had approximately $13 million outstanding under the Credit Facility and $800 million in principal amount outstanding under the notes. The immediate acceleration of debt maturities of this magnitude likely would result in our bankruptcy or other restructuring.
On May 5, 2014, we entered into an Agreement and Plan of Merger with Sabine Oil & Gas LLC (“Sabine”), under which Forest and Sabine are expected to combine their businesses in an all-stock transaction. This agreement was amended on July 9, 2014 primarily to change the structure of the transaction. If the transaction is completed, the Credit Facility will be terminated before any breach of the financial covenant occurs. Accordingly, we have elected to defer seeking an amendment or waiver to address a potential breach rather than incurring the expense of doing so at the present time solely to avoid a “going concern” audit opinion. If, prior to year end, it appears the combination transaction will not be completed, we will again evaluate the likelihood of a breach of the financial covenant and, based on that evaluation, attempt to undertake mitigating actions with respect to the Credit Facility that we feel are most appropriate. However, there can be no assurance that any particular actions will be available to us, or that even if available, we will be able to complete them. If the combination transaction is not completed, failure to take appropriate mitigating actions in the event we are in breach of the covenant may have severely negative effects on our financial condition including, potentially, bankruptcy.

We obtained amendments to the Credit Facility as recently as September 2013 and March 2014 in order to avoid breaching the debt to EBITDA covenant. We believe that we could seek, and the lenders under our Credit Facility would provide, another amendment, or a waiver, of the covenant. Failing an amendment or waiver, we believe we could sell assets to avoid breaching the financial covenant. Alternatively, we could obtain a new credit


33

facility or other sources of financing. We may yet undertake some or all of these actions prior to year end, if necessary, though there is no assurance we could complete any such actions as each involves factors that are outside our control. However, inasmuch as we have not obtained a waiver or amendment to the bank credit facility, or pursued any of the other alternatives, there presently exists substantial doubt as to our ability to continue as a going concern through December 31, 2014.

Historical Cash Flow
 
Net cash provided by operating activities, net cash (used) provided by investing activities, and net cash provided (used) by financing activities for the three months ended March 31, 2014 and 2013 were as follows:

 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Net cash provided by operating activities
$
8,846

 
$
34,322

Net cash (used) provided by investing activities
(47,661
)
 
211,872

Net cash provided (used) by financing activities
20,951

 
(246,025
)
 
Net cash provided by operating activities is primarily affected by sales volumes and commodity prices, net of the effects of settlements of our derivative instruments and changes in working capital. The decrease in net cash provided by operating activities in the three months ended March 31, 2014 compared to the three months ended March 31, 2013, was primarily due to (i) decreased revenues in 2014 as compared to 2013, which was caused primarily by lower sales volumes attributable to divestitures of oil and natural gas properties in South Texas and the Texas Panhandle, which occurred in February 2013 and November 2013, respectively, and (ii) increased cash expenses related to drilling rig stacking and operating lease terminations in 2014 as compared to 2013 (see Note 9 to the Condensed Consolidated Financial Statements for more information on drilling rig stacking and lease terminations). These decreases were partially offset by (i) lower production expense in 2014 as compared to 2013, which is attributable to the oil and natural gas properties divestitures, and (ii) a decreased investment in working capital in 2014 as compared to 2013.

The components of net cash (used) provided by investing activities for the three months ended March 31, 2014 and 2013 were as follows:
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Exploration, development, and leasehold acquisition costs(1)
$
(46,380
)
 
$
(101,665
)
Proceeds from sales of assets
2,239

 
313,805

Other property and equipment
(3,520
)
 
(268
)
Net cash (used) provided by investing activities
$
(47,661
)
 
$
211,872

____________________________________________
(1)
Cash paid for exploration, development, and leasehold acquisition costs as reflected in the Condensed Consolidated Statements of Cash Flows differs from the reported capital expenditures in the “Capital Expenditures” table below due to the timing of when the capital expenditures are incurred and when the actual cash payments are made, as well as non-cash capital expenditures such as capitalized stock-based compensation costs.
 
Net cash (used) provided by investing activities is primarily comprised of expenditures for the acquisition, exploration, and development of oil and natural gas properties, net of proceeds from the divestitures of oil and natural gas properties and other capital assets. The change in net cash used by investing activities in the three


34

months ended March 31, 2014 compared to the corresponding period of 2013 was primarily due to a decrease in proceeds from the sale of assets partially offset by a decrease in exploration, development, and leasehold acquisition cost expenditures. Expenditures for the acquisition, exploration, and development of oil and natural gas properties decreased for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013 due to the Texas Panhandle divestiture that occurred in November 2013. Acquisition, exploration, and development expenditures for the Texas Panhandle properties approximated $51 million during the three months ended March 31, 2013. Net cash provided by investing activities in the three months ended March 31, 2013 consisted principally of the net proceeds received for the South Texas divestiture that occurred in February 2013.
 
Net cash provided by financing activities of $21 million during the three months ended March 31, 2014 consisted primarily of a change in bank overdrafts of $22 million. Net cash used by financing activities of $246 million during the three months ended March 31, 2013 consisted primarily of $321 million used for the redemption of the 8½% senior notes due 2014, offset partially by net proceeds from bank borrowings of $75 million.

Capital Expenditures
 
Expenditures for property exploration, development, and leasehold acquisitions were as follows:
 
 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Exploration, development, and acquisition costs:
 

 
 
Direct costs:
 

 
 
Exploration and development
$
41,242

 
$
115,823

Leasehold acquisitions
88

 
2,605

Overhead capitalized
4,558

 
12,298

Interest capitalized
—

 
191

Total capital expenditures(1) 
$
45,888

 
$
130,917

____________________________________________
(1)
Total capital expenditures include cash expenditures, accrued expenditures, and non-cash capital expenditures including stock-based compensation capitalized under the full cost method of accounting. Total capital expenditures also include changes in estimated discounted asset retirement obligations of $(.2) million and $.3 million recorded during the three months ended March 31, 2014 and 2013, respectively.

We have established a drilling and completion capital budget of $260 million to $270 million (excluding property acquisitions, capitalized overhead, and changes in asset retirement obligations) for 2014, which will be allocated approximately 64% to Ark-La-Tex and 36% to Eagle Ford. We expect to fund these capital expenditures with a combination of cash from operations and borrowings under our Credit Facility. Primary factors impacting the level of our capital expenditures include oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions. In addition, capital expenditures will depend on availability under our Credit Facility.

FORWARD-LOOKING STATEMENTS
 
The information in this Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” the negative of such words or other variations of such words,


35

and similar expressions, identify forward-looking statements. Similarly, statements that describe our strategies, initiatives, objectives, plans, or goals are forward-looking. These forward-looking statements are based on our current intent, plans, beliefs, expectations, estimates, projections, forecasts, and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These statements are not guarantees of future performance.

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

•
estimates of our oil and natural gas reserves;

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

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

•
our future revenues, cash flows, and expenses;

•
our access to capital and our anticipated liquidity;

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

•
our outlook on oil and natural gas prices;

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

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

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

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

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

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

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

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

We believe the expectations, estimates, projections, beliefs, forecasts, and assumptions reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil and natural gas. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included or incorporated in Part I of our 2013 Annual Report on Form 10-K.
 


36

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
 
We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information to reflect events or circumstances after the filing of this report with the SEC, except as required by law. All forward-looking statements, expressed or implied, included in this Form 10-Q and attributable to Forest are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or persons acting on our behalf may issue. 


37

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

 
Three Months Ended
 
March 31,
 
2014
 
2013
 
(In Thousands)
Net loss
$
(21,007
)
 
$
(67,948
)
Income tax (benefit) expense
(1,214
)
 
337

Unrealized losses on derivative instruments, net
8,391

 
38,311

Interest expense
16,011

 
36,128

Loss on asset disposition, net
794

 
—

Write-off of debt issuance costs
3,323

 
—

Loss on debt extinguishment
—

 
25,223

Accretion of asset retirement obligations
513

 
1,244

Depreciation, depletion, and amortization
21,415

 
48,543

Stock-based compensation
794

 
3,647

Employee-related asset disposition costs
579

 
5,821

Rig stacking/lease termination
5,184

 
3,038

Adjusted EBITDA
$
34,783

 
$
94,344


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



38

Item 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We are exposed to market risk, including the effects of adverse changes in commodity prices, interest rates, and foreign currency exchange rates as discussed below.
 
Commodity Price Risk
 
We produce and sell natural gas, oil, and NGLs in the United States. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. In order to reduce the impact of fluctuations in commodity prices, we make use of a commodity hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other derivative instruments with counterparties who, in general, are lenders, or affiliates of such lenders, under our Credit Facility. These instruments, which are typically based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.
 
Swaps
 
In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher than the fixed price, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. The table below sets forth our outstanding swaps as of March 31, 2014.
 
Commodity Swaps
 
 
Natural Gas (NYMEX HH)
 
Oil (NYMEX WTI)
Remaining Swap Term
 
Bbtu
per Day
 
Weighted
Average
Hedged Price
per MMBtu
 
Fair Value
(In Thousands)
 
Barrels
per Day
 
Weighted
Average
Hedged Price
per Bbl
 
Fair Value
(In Thousands)
April 2014 - December 2014
 
70

 
$
4.38

 
$
(1,675
)
 
3,500

 
$
95.34

 
$
(2,294
)
Calendar 2015
 
50

 
4.21

 
81

 
1,000

 
89.25

 
(231
)

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

Commodity Collars
 
 
Natural Gas
(NYMEX HH)
Collar Term
 
Bbtu
Per Day
 
Hedged Floor and Ceiling Price
per MMBtu
 
Fair Value (In Thousands)
January 2015 - March 2015
 
20

 
$ 4.50/5.31
 
$
306

Calendar 2015
 
10

 
        4.10/4.30
 
(54
)



39

Commodity Options
 
In connection with several of our natural gas and oil swaps, we granted option instruments (swaptions and puts) to the swap counterparties in exchange for our receiving premium hedged prices on the natural gas and oil swaps. Under the terms of the swaption agreements, the counterparties have the option to enter into future swaps with us. The swaptions may not be exercised until their expiration dates. Under the terms of the put agreements, the counterparties have the option to put specified quantities of oil to us at specified prices. The puts may be exercised monthly by the counterparties. The table below sets forth the outstanding options as of March 31, 2014.

Commodity Options
 
 
 
 
Natural Gas (NYMEX HH)
 
Oil (NYMEX WTI)
Underlying Term
 
Option Expiration
 
Underlying
Bbtu
Per Day
 
Underlying
Hedged
Price
per MMBtu
 
Fair Value
(In
Thousands)
 
Underlying
Barrels
Per Day
 
Underlying
 Hedged
Price per
Bbl
 
Fair Value
(In
Thousands)
Gas Swaptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Calendar 2016
 
December 2014
 
10

 
$
4.18

 
$
(693
)
 
—

 
$
—

 
$
—

Oil Swaptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Calendar 2015
 
December 2014
 
—

 
—

 
—

 
3,000

 
100.00

 
(1,354
)
Calendar 2015
 
December 2014
 
—

 
—

 
—

 
1,000

 
106.00

 
(182
)
Calendar 2015
 
December 2014
 
—

 
—

 
—

 
1,000

 
99.00

 
(513
)
Calendar 2016
 
December 2015
 
—

 
—

 
—

 
1,000

 
98.00

 
(672
)
Oil Put Options:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Monthly Calendar 2014
 
Monthly Calendar 2014
 
—

 
—

 
—

 
2,000

 
70.00

 
(60
)
 
The estimated fair value at March 31, 2014 of all our commodity derivative instruments based on various valuation inputs, including published forward prices, was a net liability of approximately $7 million.

Derivative Fair Value Reconciliation
 
The table below sets forth the changes that occurred in the fair values of our commodity derivative instruments during the three months ended March 31, 2014, beginning with the fair value of our derivative instruments on December 31, 2013. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Due to the volatility of oil and natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period. Actual cash settlements recognized related to our commodity derivative instruments will likely differ from those estimated at March 31, 2014 and will depend exclusively on the price of the commodities on the settlement dates specified by the derivative instruments.
 
 
Fair Value of Derivative Contracts
 
(In Thousands)
As of December 31, 2013
$
1,050

Net decrease in fair value
(12,851
)
Net cash settlements paid
4,460

As of March 31, 2014
$
(7,341
)



40


Interest Rate Risk
 
The following table presents principal amounts and related interest rates by year of maturity for senior notes at March 31, 2014.
 
 
2019
 
2020
 
Total
 
 
Senior notes:
 

 
 
 
 

Principal (in thousands)
$
577,914

 
$
222,087

 
$
800,001

Fixed interest rate
7.25
%
 
7.50
%
 
7.32
%
Effective interest rate(1)
7.24
%
 
7.50
%
 
7.32
%
____________________________________________
(1)
The effective interest rate on the 7.25% senior notes due 2019 differs from the fixed interest rate due to the amortization of the related premium on the notes.

Foreign Currency Exchange Risk

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

Item 4.  CONTROLS AND PROCEDURES
 
Evaluation of Disclosure Controls and Procedures
 
Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Victor A. Wind, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the quarterly period ended March 31, 2014 (the “Evaluation Date”). Because of the matters discussed below under “Internal Control Issues,” 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.
 
Internal Control Issues
Forest’s periodic evaluation of its disclosure controls and procedures includes an assessment of its internal control over financial reporting, which is designed to provide reasonable assurance regarding the reliability of Forest’s financial reporting and the preparation of Forest’s financial statements. In connection with the audit of our year end financial statements, Forest’s independent registered public accounting firm, Ernst & Young LLP (“EY”), is responsible for auditing both (i) the financial statements to obtain reasonable assurance about whether they are free of material misstatement and (ii) the effectiveness of Forest’s internal control over financial reporting.  
As part of management’s assessment, and EY’s audit, of Forest’s internal control over financial reporting as of December 31, 2013, EY or Forest identified certain control deficiencies. Identification of control deficiencies regularly occurs in connection with the assessment or audit of internal control over financial reporting. Control deficiencies exist when the design or operation of a control does not allow management or employees, in the normal


41

course of performing their assigned functions, to prevent or detect misstatements on a timely basis. A control deficiency may constitute a “significant deficiency” or a “material weakness” as defined in applicable Securities and Exchange Commission (“SEC”) rules. A “significant deficiency” means a deficiency, or a combination of deficiencies, in internal control over financial reporting that is less severe than a material weakness, yet important enough to merit attention by those responsible for oversight of the registrant’s financial reporting. A “material weakness” means a deficiency or a combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the registrant’s financial statements will not be prevented or detected on a timely basis. However, not all control deficiencies rise to the level of a significant deficiency or a material weakness. Forest management and EY originally concluded that none of the identified control deficiencies constituted a material weakness in Forest’s internal control over financial reporting as of December 31, 2013, and this conclusion was reflected in our Annual Report on Form 10-K for the year ended December 31, 2013, as initially filed on February 26, 2014 (the “Form 10-K”).
Subsequent to the filing of the Form 10-K, the Public Company Accounting Oversight Board conducted an inspection of EY’s 2013 audits of Forest, and following this inspection, EY requested a reevaluation of the control deficiencies previously identified. In addition, EY and Forest’s management conducted additional analysis of other issues relating to Forest’s internal controls. After extensive consultation with outside experts, management has now concluded that each of the following control deficiencies constituted material weaknesses in Forest’s internal control over financial reporting as of December 31, 2013:

•
Information technology general controls - User access and program change management general controls were determined to be ineffective. Compensating controls designed by management lacked the level of precision needed and were ineffective because they relied on electronic data from systems with ineffective information technology general controls. Thus Forest’s controls in all areas, some of which were review controls, that relied on electronic data generated from systems with ineffective information technology general controls were inappropriately designed and operating.

•
Division of interests - Controls over division of interests were determined to be ineffective because changes to Forest’s division of interest master files are not produced in a report that is reviewed by an individual other than the preparer in order to ensure that all changes are appropriate. Further, Forest’s controls were not designed so that changes to the division of interests themselves (as opposed to the master files) would be reviewed by an individual other than the person or persons making the changes. These control deficiencies provided for the opportunity for inappropriate recognition of revenues, operating costs, capital charges, and amounts due to and from third parties as a result of incorrect division of interests.

•
Ceiling limitation test - Several controls, including review controls, associated with the inputs to the ceiling limitation test (oil and natural gas reserves, unproved properties, capital accrual, asset retirement obligations, and general and administrative cost allocation) lacked sufficient appropriate design or operating precision to prevent reasonably possible errors related to the ceiling limitation test that, when aggregated, could be material.

Accordingly, Forest’s internal control over financial reporting was ineffective at December 31, 2013. In addition, because none of the material weaknesses were adequately remediated as of March 31, 2014 or June 30, 2014, Forest’s internal control over financial reporting was ineffective at those dates as well. However, Forest has concluded that the existence of these material weaknesses did not result in a material misstatement of Forest’s financial statements included in the Form 10-K or in its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 or June 30, 2014, as initially filed on May 6, 2014 and August 18, 2014, respectively.
 
Changes in Internal Control over Financial Reporting
 
Forest has adopted, and partially implemented, a plan to remediate the material weaknesses described above in “Internal Control Issues.” The implementation of the material aspects of this plan began in the third quarter of 2014. Accordingly, there were no changes in our internal control over financial reporting that occurred during the


42

quarterly period ended March 31, 2014 that materially affected, or are likely to materially affect, our internal control over financial reporting.

As of the date of this filing, the remediation plan consists of the following main elements:
•
Information technology general controls - Forest has implemented controls pursuant to which user access to certain data is reviewed more frequently and developer access to the related software will be limited. These steps have largely been completed.

•
Division of interests - Forest will implement controls that will provide for expanded review and oversight of all changes to its division of interest master files. Forest plans to have this remediation completed by year end.

•
Ceiling limitation test - Forest will implement additional review procedures over the various inputs to the ceiling limitation test. These reviews will occur more frequently and be performed at a more refined level of precision, involving more process owners. Forest plans to have this remediation completed by year end.

We can give no assurance that the measures we take will remediate the material weaknesses that we have identified or that additional material weaknesses will not arise in the future. We will continue to monitor the effectiveness of these and other processes, procedures, and controls and will make any further changes management determines to be appropriate.




43

PART II—OTHER INFORMATION
 

Item 1.  LEGAL PROCEEDINGS

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

There have been no material changes to the disclosure included in Part I, Item 3, of the Annual Report on Form 10-K for the fiscal year ended December 31, 2013, except as noted above.
 
We are a party to various other lawsuits, claims, and proceedings in the ordinary course of business. These proceedings are subject to uncertainties inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss associated with these proceedings would not be material to our consolidated financial position; however, in the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flow.

Item 1A.  RISK FACTORS

There have been no material changes to the risks described in Part I, Item 1A, of the Annual Report on Form 10-K for the year ended December 31, 2013, as amended by the Form 10-K/A filed on October 1, 2014.

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.



44

Issuer Purchases of Equity Securities
 
The table below sets forth information regarding repurchases of our common stock during the first quarter of 2014. The shares repurchased represent shares of our common stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Forest does not consider this a share buyback program.
 
Period
 
Total # of Shares
Purchased
 
Average Price
Paid Per Share
 
Total # of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
 
Maximum # (or
Approximate Dollar
Value) of Shares that
May Yet be Purchased
Under the Plans or
Programs
January 2014
 
109,181

 
$
3.43

 
—

 
—

February 2014
 
14,810

 
2.74

 
—

 
—

March 2014
 
528

 
1.84

 
—

 
—

First Quarter Total
 
124,519

 
$
3.34

 
—

 
—



45

Item 6.  EXHIBITS
(a)

 
Exhibits.
 
 
 
3.1

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

 
 
3.2

 
Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, No. 5, and No. 6, incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-4 for Forest Oil Corporation filed June 4, 2013 (File No. 333-189064).
 
 
 
4.1

 
Second Amendment to Third Amended and Restated Credit Agreement, dated as of March 31, 2014, among Forest Oil Corporation, the lenders signatory thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 1, 2014 (File No. 001-13515).

 
 
 
10.1

 
Forest Oil Corporation 2014 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2014 (File No. 001-13515).
 
 
 
31.1*

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

 
 
31.2*

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

 
 
32.1+

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

 
 
32.2+

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

 
XBRL Instance Document.
 
 
 
101.SCH++

 
XBRL Schema Document.
 
 
 
101.CAL++

 
XBRL Calculation Linkbase Document.
 
 
 
101.LAB++

 
XBRL Label Linkbase Document.
 
 
 
101.PRE++

 
XBRL Presentation Linkbase Document.
 
 
 
101.DEF++

 
XBRL Definition Linkbase Document.
____________________________________________
*
Filed herewith.
+    Not considered to be “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section.
++    The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act, are deemed not filed for purposes of Section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.


46

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)
 
 
 
October 1, 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)



47

Exhibit Index
3.1

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

 
 
3.2

 
Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, No. 5, and No. 6, incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-4 for Forest Oil Corporation filed June 4, 2013 (File No. 333-189064).
 
 
 
4.1

 
Second Amendment to Third Amended and Restated Credit Agreement, dated as of March 31, 2014, among Forest Oil Corporation, the lenders signatory thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 1, 2014 (File No. 001-13515).

 
 
 
10.1

 
Forest Oil Corporation 2014 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2014 (File No. 001-13515).
 
 
 
31.1*

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

 
 
31.2*

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

 
 
32.1+

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

 
 
32.2+

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

 
XBRL Instance Document.
 
 
 
101.SCH++

 
XBRL Schema Document.
 
 
 
101.CAL++

 
XBRL Calculation Linkbase Document.
 
 
 
101.LAB++

 
XBRL Label Linkbase Document.
 
 
 
101.PRE++

 
XBRL Presentation Linkbase Document.
 
 
 
101.DEF++

 
XBRL Definition Linkbase Document.
____________________________________________
*
Filed herewith.
+    Not considered to be “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section.
++    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.


48

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