FST-06.30.2013-10Q
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
__________________________________________________
FORM 10-Q 
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2013
 
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.  x Yes  ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes  ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
Accelerated filer ¨
Non-accelerated filer ¨
(Do not check if a smaller reporting company)
Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨ Yes  x No

As of August 1, 2013 there were 120,078,373 shares of the registrant’s common stock, par value $.10 per share, outstanding.
 
 
 
 
 

Table of Contents

FOREST OIL CORPORATION
INDEX TO FORM 10-Q
June 30, 2013
 
 


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Table of Contents

PART I—FINANCIAL INFORMATION
 
Item 1.  FINANCIAL STATEMENTS
  
FOREST OIL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS 
(Unaudited)
(In Thousands, Except Share Amounts)
 
June 30,
2013
 
December 31,
2012
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
421

 
$
1,056

Accounts receivable
72,470

 
67,516

Derivative instruments
17,211

 
40,190

Other current assets
16,024

 
16,318

Total current assets
106,126

 
125,080

Property and equipment, at cost:
 

 
 

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

 
 

Proved, net of accumulated depletion of $8,326,395 and $8,237,186
1,288,691

 
1,459,312

Unproved
195,118

 
277,798

Net oil and natural gas properties
1,483,809

 
1,737,110

Other property and equipment, net of accumulated depreciation and amortization of $49,108 and $46,908
14,613

 
17,128

Net property and equipment
1,498,422

 
1,754,238

Deferred income taxes
6,547

 
14,681

Goodwill
239,420

 
239,420

Derivative instruments
5,504

 
8,335

Other assets
57,726

 
60,108

 
$
1,913,745

 
$
2,201,862

LIABILITIES AND SHAREHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued liabilities
$
196,260

 
$
164,786

Accrued interest
14,850

 
23,407

Derivative instruments
3,829

 
9,347

Deferred income taxes
6,547

 
14,681

Current portion of long-term debt
—

 
12

Other current liabilities
14,038

 
14,092

Total current liabilities
235,524

 
226,325

Long-term debt
1,630,337

 
1,862,088

Asset retirement obligations
23,247

 
56,155

Derivative instruments
2,310

 
7,204

Other liabilities
89,713

 
92,914

Total liabilities
1,981,131

 
2,244,686

Shareholders’ equity:
 

 
 

Preferred stock, none issued and outstanding
—

 
—

Common stock, 120,107,896 and 118,245,320 shares issued and outstanding
12,011

 
11,825

Capital surplus
2,550,933

 
2,541,859

Accumulated deficit
(2,610,503
)
 
(2,575,994
)
Accumulated other comprehensive loss
(19,827
)
 
(20,514
)
Total shareholders’ equity (deficit)
(67,386
)
 
(42,824
)
 
$
1,913,745

 
$
2,201,862


See accompanying Notes to Condensed Consolidated Financial Statements. 


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Table of Contents

FOREST OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In Thousands, Except Per Share Amounts)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Revenues:
 

 
 

 
 

 
 

Oil, natural gas, and natural gas liquids sales
$
116,786

 
$
135,694

 
$
234,828

 
$
294,595

Interest and other
28

 
37

 
160

 
69

Total revenues
116,814

 
135,731

 
234,988

 
294,664

Costs, expenses, and other:
 

 
 

 
 

 
 

Lease operating expenses
19,167

 
27,134

 
40,371

 
54,741

Production and property taxes
5,029

 
6,940

 
7,245

 
18,093

Transportation and processing costs
3,098

 
3,615

 
6,378

 
7,587

General and administrative
13,114

 
16,421

 
33,128

 
31,805

Depreciation, depletion, and amortization
43,804

 
72,987

 
92,347

 
139,957

Ceiling test write-down of oil and natural gas properties
—

 
348,976

 
—

 
383,793

Interest expense
29,392

 
34,317

 
65,520

 
67,709

Realized and unrealized gains on derivative instruments, net
(31,610
)
 
(34,015
)
 
(6,030
)
 
(63,539
)
Other, net
1,593

 
3,455

 
30,413

 
30,375

Total costs, expenses, and other
83,587

 
479,830

 
269,372

 
670,521

Earnings (loss) before income taxes
33,227

 
(344,099
)
 
(34,384
)
 
(375,857
)
Income tax (benefit) expense
(212
)
 
167,074

 
125

 
167,989

Net earnings (loss)
$
33,439

 
$
(511,173
)
 
$
(34,509
)
 
$
(543,846
)
 
 
 
 
 
 
 
 
Basic earnings (loss) per common share
$
.28

 
$
(4.44
)
 
$
(.30
)
 
$
(4.75
)
Diluted earnings (loss) per common share
$
.28

 
$
(4.44
)
 
$
(.30
)
 
$
(4.75
)























See accompanying Notes to Condensed Consolidated Financial Statements.


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

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Net earnings (loss)
$
33,439

 
$
(511,173
)
 
$
(34,509
)
 
$
(543,846
)
Other comprehensive income:
 

 
 

 
 

 
 

Defined benefit postretirement plans - amortization of actuarial losses, net of tax
345

 
186

 
687

 
373

Total other comprehensive income
345

 
186

 
687

 
373

 
 
 
 
 
 
 
 
Total comprehensive income (loss)
$
33,784

 
$
(510,987
)
 
$
(33,822
)
 
$
(543,473
)









































See accompanying Notes to Condensed Consolidated Financial Statements. 


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Table of Contents

FOREST OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(Unaudited)
(In Thousands)
 
Common Stock
 
Capital Surplus
 
Accumulated Deficit
 
Accumulated
Other
Comprehensive Income (Loss)
 
Total
Shareholders’ Equity (Deficit)
 
Shares
 
Amount
 
 
 
 
Balances at December 31, 2012
118,245

 
$
11,825

 
$
2,541,859

 
$
(2,575,994
)
 
$
(20,514
)
 
$
(42,824
)
Employee stock purchase plan
115

 
11

 
431

 
—

 
—

 
442

Restricted stock issued, net of forfeitures
1,978

 
198

 
(198
)
 
—

 
—

 
—

Amortization of stock-based compensation
—

 
—

 
10,147

 
—

 
—

 
10,147

Other, net
(230
)
 
(23
)
 
(1,306
)
 
—

 
—

 
(1,329
)
Net loss
—

 
—

 
—

 
(34,509
)
 
—

 
(34,509
)
Other comprehensive income
—

 
—

 
—

 
—

 
687

 
687

Balances at June 30, 2013
120,108

 
$
12,011

 
$
2,550,933

 
$
(2,610,503
)
 
$
(19,827
)
 
$
(67,386
)
 







































See accompanying Notes to Condensed Consolidated Financial Statements.


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

Six Months Ended
 
June 30,
 
2013
 
2012
Operating activities:
 

 
 

Net loss
$
(34,509
)
 
$
(543,846
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion, and amortization
92,347

 
139,957

Deferred income tax
—

 
167,880

Unrealized losses (gains) on derivative instruments, net
15,398

 
(5,423
)
Ceiling test write-down of oil and natural gas properties
—

 
383,793

Stock-based compensation expense
6,479

 
9,257

Loss on debt extinguishment
25,223

 
—

Other, net
2,903

 
7,833

Changes in operating assets and liabilities:
 

 
 

Accounts receivable
(4,168
)
 
19,077

Other current assets
(269
)
 
2,305

Accounts payable and accrued liabilities
17,956

 
(20,601
)
Accrued interest and other
(10,948
)
 
16,192

Net cash provided by operating activities
110,412

 
176,424

Investing activities:
 

 
 

Capital expenditures for property and equipment:
 

 
 

Exploration, development, and leasehold acquisition costs
(205,099
)
 
(395,781
)
Other fixed assets
(1,115
)
 
(4,910
)
Proceeds from sales of assets
338,977

 
1,102

Net cash provided (used) by investing activities
132,763

 
(399,589
)
Financing activities:
 

 
 

Proceeds from bank borrowings
320,000

 
443,000

Repayments of bank borrowings
(255,000
)
 
(200,000
)
Redemption of senior notes
(321,327
)
 
—

Change in bank overdrafts
13,523

 
(20,666
)
Other, net
(1,006
)
 
(1,501
)
Net cash (used) provided by financing activities
(243,810
)
 
220,833

Net decrease in cash and cash equivalents
(635
)
 
(2,332
)
Cash and cash equivalents at beginning of period
1,056

 
3,012

Cash and cash equivalents at end of period
$
421

 
$
680

Cash paid during the period for:
 

 
 

Interest (net of capitalized amounts)
$
70,428

 
$
61,622

Income taxes (net of refunded amounts)
1,070

 
915

Non-cash investing activities:


 


(Decrease) increase in accrued capital expenditures
$
(4,259
)
 
$
5,672

Common stock issued for acquisition of unproved oil and natural gas properties
—

 
36,431

 









See accompanying Notes to Condensed Consolidated Financial Statements.


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

(1) ORGANIZATION AND BASIS OF PRESENTATION
 
Organization
 
Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. Forest holds assets in several exploration and producing areas in the United States and has exploratory and development interests in two other countries. Unless the context indicates otherwise, the terms “Forest,” the “Company,” “we,” “our,” and “us,” as used in this Quarterly Report on Form 10-Q, refer to Forest Oil Corporation and its subsidiaries.
 
Basis of Presentation
 
The Condensed Consolidated Financial Statements included herein are unaudited and include the accounts of Forest and its consolidated subsidiaries. All intercompany balances and transactions have been eliminated. In the opinion of management, all adjustments, which are of a normal recurring nature, have been made that are necessary for a fair presentation of the financial position of Forest at June 30, 2013, and the results of its operations, its comprehensive income, its cash flows, and changes in its shareholders’ equity for the periods presented. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in the prices of oil, natural gas, and NGLs and the impact the prices have on Forest’s revenues and the fair values of its derivative instruments.
 
In the course of preparing the Condensed Consolidated Financial Statements, management makes various assumptions, judgments, and estimates to determine the reported amounts of assets, liabilities, revenues, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.
 
The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of oil, natural gas, and NGL reserves used in calculating depletion, the amount of future net revenues used in computing the ceiling test limitations, and the amount of future capital costs and abandonment obligations used in such calculations, assessing investments in unproved properties and goodwill for impairment, determining the need for and the amount of deferred tax asset valuation allowances, and estimating fair values of financial instruments, including derivative instruments.

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

For a more complete understanding of Forest’s operations, financial position, and accounting policies, reference is made to the consolidated financial statements of Forest, and related notes thereto, filed with Forest’s Annual Report on Form 10-K for the year ended December 31, 2012, previously filed with the Securities and Exchange Commission (“SEC”).

(2) EARNINGS (LOSS) PER SHARE

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


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shareholder return over the performance units’ vesting period in relation to the shareholder returns of specified peers. See Note 3 for more information on Forest’s stock-based incentive awards. In summary, restricted stock issued to employees and directors and phantom stock units issued to directors are participating securities, and earnings are allocated to both common stock and these participating securities under the two-class method. However, these participating securities do not have a contractual obligation to share in Forest’s losses. Therefore, in periods of net loss, none of the loss is allocated to these participating securities.

Diluted earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period, increasing the denominator to include the number of additional common shares that would have been outstanding if the dilutive potential common shares (e.g. stock options, unvested restricted stock, unvested phantom stock units that may be settled in shares, and unvested performance units) had been issued. Additionally, the numerator is also adjusted for certain contracts that provide the issuer or holder with a choice between settlement methods. Diluted earnings per share is computed using the more dilutive of the treasury stock method or the two-class method. Under the treasury stock method, the dilutive effect of potential common shares is computed by assuming common shares are issued for these securities at the beginning of the period, with the assumed proceeds from exercise, which include average unamortized stock-based compensation costs, assumed to be used to purchase common shares at the average market price for the period, and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) included in the denominator of the diluted earnings per share computation. The number of contingently issuable shares pursuant to the outstanding performance units is included in the denominator of the computation of diluted earnings per share based on the number of shares, if any, that would be issuable if the end of the reporting period were the end of the contingency period and if the result would be dilutive. Under the two-class method, the dilutive effect of non-participating potential common shares is determined and undistributed earnings are reallocated between common shares and participating securities. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the six months ended June 30, 2013 and the three and six months ended June 30, 2012. Unvested restricted stock grants were not included in the calculation of diluted earnings per share for the three months ended June 30, 2013 as their inclusion would have an antidilutive effect.
 
The following reconciles net earnings (loss) as reported in the Condensed Consolidated Statements of Operations to net earnings (loss) used for computing basic and diluted earnings (loss) per share for the periods presented.
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Net earnings (loss)
$
33,439

 
$
(511,173
)
 
$
(34,509
)
 
$
(543,846
)
Less: net earnings attributable to participating securities
(1,014
)
 
—

 
—

 
—

Net earnings (loss) for basic and diluted earnings (loss) per share
$
32,425

 
$
(511,173
)
 
$
(34,509
)
 
$
(543,846
)

The following reconciles basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the periods presented.
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Weighted average common shares outstanding during the period for basic earnings (loss) per share
116,033

 
115,107

 
115,845

 
114,464

Dilutive effects of potential common shares
—

 
—

 
—

 
—

Weighted average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings (loss) per share
116,033

 
115,107

 
115,845

 
114,464



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

Compensation Costs
 
The table below sets forth stock-based compensation for the three and six months ended June 30, 2013 and 2012, and the remaining unamortized amounts and weighted average amortization period as of June 30, 2013.
 
 
Restricted
Stock
 
Performance
Units
 
Phantom
Stock Units
 
Total(1)(2)
 
(In Thousands)
Three Months Ended June 30, 2013:
 

 
 

 
 

 
 

Total stock-based compensation costs
$
3,210

 
$
1,105

 
$
513

 
$
4,828

Less: stock-based compensation costs capitalized
(1,172
)
 
(241
)
 
(218
)
 
(1,631
)
Stock-based compensation costs expensed
$
2,038

 
$
864

 
$
295

 
$
3,197

Six Months Ended June 30, 2013:
 

 
 

 
 

 
 

Total stock-based compensation costs
$
7,445

 
$
2,733

 
$
1,775

 
$
11,953

Less: stock-based compensation costs capitalized
(2,994
)
 
(714
)
 
(887
)
 
(4,595
)
Stock-based compensation costs expensed
$
4,451

 
$
2,019

 
$
888

 
$
7,358

Unamortized stock-based compensation costs(3)
$
20,149

 
$
11,252

 
$
8,562

 
$
39,963

Weighted average amortization period remaining
1.8 years

 
2.3 years

 
2.0 years

 
2.0 years

Three Months Ended June 30, 2012:
 

 
 

 
 

 
 

Total stock-based compensation costs
$
4,943

 
$
3,145

 
$
(1,046
)
 
$
7,042

Less: stock-based compensation costs capitalized
(1,487
)
 
(477
)
 
369

 
(1,595
)
Stock-based compensation costs expensed
$
3,456

 
$
2,668

 
$
(677
)
 
$
5,447

Six Months Ended June 30, 2012:
 

 
 

 
 

 
 

Total stock-based compensation costs
$
8,719

 
$
4,357

 
$
(113
)
 
$
12,963

Less: stock-based compensation costs capitalized
(3,195
)
 
(867
)
 
(130
)
 
(4,192
)
Stock-based compensation costs expensed
$
5,524

 
$
3,490

 
$
(243
)
 
$
8,771

____________________________________________
(1)
Forest also maintains an employee stock purchase plan (which is not included in the table) under which $.1 million and $.2 million of compensation cost was recognized for the three and six month periods ended June 30, 2013, respectively, and $.1 million and $.2 million of compensation cost was recognized for the three and six month periods ended June 30, 2012, respectively.
(2)
In connection with the divestiture of the South Texas oil and natural gas properties in the first quarter of 2013, Forest incurred one-time employee termination benefit costs that included $2.0 million ($1.0 million net of capitalized amounts) in stock-based compensation costs due to accelerated vesting of the affected awards. In addition to these stock-based compensation costs, in the first quarter of 2013, Forest incurred $7.5 million ($5.7 million net of capitalized amounts) in other one-time employee termination benefit costs related to this divestiture. All of these one-time employee termination benefit costs expenses are included in “General and administrative” in the Condensed Consolidated Statement of Operations for the six months ended June 30, 2013 and no further one-time employee termination benefit costs are expected to be made for this specific divestiture. See Note 5 for more information regarding this divestiture.
(3)
The unamortized stock-based compensation costs for liability-based awards are based on the closing price of Forest’s common stock at the reporting period end.
 


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Stock Options
 
The following table summarizes stock option activity in the Plans for the six months ended June 30, 2013. 
 
Number of
Options
 
Weighted
Average Exercise
Price
 
Aggregate
Intrinsic Value
(In Thousands)(1)
 
Number of
Options
Exercisable
Outstanding at January 1, 2013
870,816

 
$
17.86

 
$
—

 
870,816

Granted
—

 
—

 
 

 
 

Exercised
—

 
—

 
—

 
 

Cancelled
(217,046
)
 
20.01

 
 

 
 

Outstanding at June 30, 2013
653,770

 
$
17.14

 
$
—

 
653,770

____________________________________________
(1)
The intrinsic value of a stock option is the amount by which the market value of the underlying stock, as of the date outstanding or exercised, exceeds the exercise price of the option.
 
Restricted Stock, Performance Units, and Phantom Stock Units
 
The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Plans for the six months ended June 30, 2013.
 
 
Restricted Stock
 
Performance Units
 
Phantom Stock Units
 
Number of
Shares
 
Weighted
Average
Grant
Date
Fair
Value
 
Vest Date
Fair
Value
(In
Thousands)
 
Number
of
Units
 
Weighted
Average
Grant
Date
Fair
Value
 
Vest Date
Fair
Value
(In
Thousands)
 
Number
of
Units(1)
 
Weighted
Average
Grant
Date
Fair
Value
 
Vest Date
Fair
Value
(In
Thousands)
Unvested at January 1, 2013
2,721,637

 
$
17.64

 
 

 
939,180

 
$
15.20

 
 

 
1,161,737

 
$
9.91

 
 

Awarded(2)
2,151,877

 
6.04

 
 

 
1,182,500

 
5.47

 
 

 
1,619,401

 
6.43

 
 

Vested
(806,959
)
 
21.50

 
$
4,514

 
(203,240
)
 
19.60

 
$
—

 
(90,821
)
 
10.49

 
$
615

Forfeited
(174,335
)
 
16.00

 
 

 
—

 
—

 
 

 
(94,507
)
 
10.03

 
 

Unvested at June 30, 2013
3,892,220

 
$
10.50

 
 

 
1,918,440

 
$
8.74

 
 

 
2,595,810

 
$
7.71

 
 

 ____________________________________________
(1)
All of the unvested units of phantom stock at June 30, 2013 must be settled in cash. The phantom stock units have been accounted for as a liability within the Condensed Consolidated Financial Statements. All of the phantom stock units that vested during the six months ended June 30, 2013 were settled in cash.
(2)
Of the restricted stock shares granted during the six months ended June 30, 2013, 1,229,901 shares vest in increments of 33.3% on each of the first three anniversary dates of the grant. All other Forest restricted stock grants cliff vest on the third anniversary of the date of grant. Additionally, during the six months ended June 30, 2013, Forest granted 950,000 performance units that are cash-settled, with the settlement amount dependent upon Forest’s relative total shareholder return in comparison to an identified peer group over a thirty-six month performance period. These performance units have been accounted for as a liability within the Condensed Consolidated Financial Statements. All of the other outstanding performance units are share-settled and utilize the same relative total shareholder return criteria to determine the settlement amount, other than certain peers used for comparison purposes. The share-settled performance units have been accounted for as equity-based awards within the Condensed Consolidated Financial Statements.



9
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(4) DEBT
 
The components of debt are as follows:
 
 
June 30, 2013
 
December 31, 2012
 
Principal
 
Unamortized
Premium
 
Total
 
Principal
 
Unamortized
Premium
(Discount)
 
Total
 
(In Thousands)
Credit facility
$
130,000

 
$
—

 
$
130,000

 
$
65,000

 
$
—

 
$
65,000

7% senior subordinated notes due 2013(1)
—

 
—

 
—

 
12

 
—

 
12

8½% senior notes due 2014(2)
—

 
—

 
—

 
300,000

 
(3,277
)
 
296,723

7¼% senior notes due 2019
1,000,000

 
337

 
1,000,337

 
1,000,000

 
365

 
1,000,365

7½% senior notes due 2020
500,000

 
—

 
500,000

 
500,000

 
—

 
500,000

Total debt
1,630,000

 
337

 
1,630,337

 
1,865,012

 
(2,912
)
 
1,862,100

Less: current portion of long-term debt
—

 
—

 
—

 
(12
)
 
—

 
(12
)
Long-term debt
$
1,630,000

 
$
337

 
$
1,630,337

 
$
1,865,000

 
$
(2,912
)
 
$
1,862,088

____________________________________________
(1)
In June 2013, Forest redeemed the 7% senior subordinated notes due 2013 at their maturity.
(2)
In March 2013, Forest redeemed the 8½% senior notes due 2014 at 107.11% of par, recognizing a loss of $25.2 million upon redemption.

Bank Credit Facility
 
As of June 30, 2013, the Company had a $1.5 billion credit facility (the “Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A. (the “Administrative Agent”), which matures in June 2016. The size of the Credit Facility may be increased by $300.0 million, to a total of $1.8 billion, upon agreement between the applicable lenders and Forest.

Forest’s availability under the Credit Facility is governed by a borrowing base. As of June 30, 2013, the borrowing base under the Credit Facility was $900.0 million. The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of Forest’s oil and 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 included in the borrowing base, as applicable, having a fair market value in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount 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, discussed in Note 5, resulted in a $170.0 million reduction to the borrowing base effective February 15, 2013.

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

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant. The Credit Facility provides that Forest will not permit its ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.50 to 1.00 at any time. Depending on Forest’s overall level of indebtedness, this covenant may limit its ability to borrow


10
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funds as needed under the Credit Facility. Forest’s ratio of total debt outstanding to EBITDA for the twelve-month period ended June 30, 2013, as calculated in accordance with the Credit Facility, was 4.37.

At June 30, 2013, there were outstanding borrowings of $130.0 million under the Credit Facility at a weighted average interest rate of 1.8%, 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 June 30, 2013 and 2012, Forest capitalized $8.1 million and $8.8 million, respectively, of general and administrative costs (including stock-based compensation). During the six months ended June 30, 2013 and 2012, Forest capitalized $20.4 million and $20.3 million, respectively, of general and administrative costs (including stock-based compensation). During the three months ended June 30, 2013 and 2012, Forest capitalized $.9 million and $1.9 million, respectively, of interest costs attributed to unproved properties. During the six months ended June 30, 2013 and 2012, Forest capitalized $1.1 million and $4.1 million, respectively, of interest costs attributed to unproved properties.

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

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

Although Forest did not incur a ceiling test write-down at March 31, 2013 or June 30, 2013, ceiling test write-downs of the United States cost center may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenues from estimated production of proved oil and natural gas reserves declines compared to prices used as of June 30, 2013, unproved property values decrease, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center.

During the three and six months ended June 30, 2012, Forest recorded ceiling test write-downs of oil and natural gas property costs of $349.0 million and $383.8 million, respectively, primarily due to a decrease in natural gas prices used in the calculation of the present value of future net revenues as of June 30, 2012. During the three months ended March 31, 2012, Forest recorded a $34.8 million ceiling test write-down of its Italian cost center due to an Italian regional regulatory body’s denial of approval of an environmental impact assessment associated with Forest’s proposal to commence natural gas production from wells that Forest drilled and completed in 2007. Forest is currently appealing the region’s denial; however, until the region’s denial is reversed or overturned, Forest determined that it could no longer conclude with reasonable certainty


11
Table of Contents

that its Italian natural gas reserves were producible and, therefore, reclassified the reserves from proved to probable, incurring a ceiling test write-down.

Gain or loss is not recognized on the sale of oil and natural gas properties unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and natural gas reserves attributable to a cost center.
 
Depletion of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Company uses its quarter-end reserves estimates to calculate depletion for the current quarter.

Divestitures

In January 2013, Forest entered into an agreement to sell all of its oil and natural gas properties located in South Texas, excluding its Eagle Ford Shale oil properties, for $325.0 million in cash. This transaction closed on February 15, 2013 and was subject to customary purchase price adjustments, resulting in Forest receiving net proceeds of $321.0 million during the six months ended June 30, 2013.

In July 2013, Forest announced that it will initiate a marketed process to pursue the potential sale of its oil and natural gas properties located in the Texas Panhandle Area. If the sale of these assets is completed, Forest intends to use the proceeds to reduce its indebtedness.

Acquisition and Development Agreement

In April 2013, Forest entered into an Acquisition and Development Agreement (“ADA”) with a third-party for the future development of Forest’s Eagle Ford Shale acreage in Gonzales County, Texas. Under the terms of the ADA, the third-party will pay a $90.0 million drilling carry in the form of future drilling and completion services and related development capital in exchange for a 50% working interest in Forest’s Eagle Ford Shale acreage position. Upon completion of the phased contribution of the drilling carry, Forest and the third-party will participate in future drilling on a 50/50 basis. The ADA applies to wells spud on or subsequent to November 28, 2012, none of which had been placed on production prior to April 1, 2013, and Forest retained all of its interests in wells and production that were spud prior to November 28, 2012. Forest is the operator of the drilling program. As of June 30, 2013, Forest had realized $36.2 million of the drilling carry and currently expects that it will be fully realized by mid-2014.

Asset Retirement Obligations

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

The following table summarizes the activity for Forest’s asset retirement obligations for the period indicated:
 
Six Months Ended June 30, 2013
 
(In Thousands)
Asset retirement obligations at beginning of period
$
58,585

Accretion expense
1,793

Liabilities incurred
1,122

Liabilities settled
(1,252
)
Disposition of properties
(34,024
)
Revisions of estimated liabilities
(473
)
Asset retirement obligations at end of period
25,751

Less: current asset retirement obligations
(2,504
)
Long-term asset retirement obligations
$
23,247





12
Table of Contents

(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 (.6)% and (.4)% for the three and six months ended June 30, 2013, respectively, and (49)% and (45)% for the three and six months ended June 30, 2012, respectively, were primarily due to changes in the valuation allowance on Forest’s deferred tax assets.

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

Negative evidence considered by Forest included a three-year cumulative book loss driven primarily by the ceiling test write-downs incurred in 2012. Positive evidence considered by Forest included forecasted book income in future periods based on expected future oil, natural gas, and NGL production and expected commodity prices based on NYMEX oil and natural gas futures. Based upon the evaluation of what was determined to be relevant evidence, Forest has recorded a valuation allowance against its deferred tax assets.
 
(7) FAIR VALUE MEASUREMENTS
 
Forest’s assets and liabilities measured at fair value on a recurring basis at June 30, 2013 and December 31, 2012 are set forth in the table below.
 
 
 
June 30, 2013
 
December 31, 2012
 
 
Using Significant Other Observable Inputs
(Level 2)(1)
 
 
(In Thousands)
Assets:
 
 

 
 
Derivative instruments(2):
 
 

 
 
Commodity
 
$
22,715

 
$
35,465

Interest rate
 
—

 
13,060

Total assets
 
$
22,715

 
$
48,525

Liabilities:
 
 

 
 
Derivative instruments(2):
 
 

 
 
Commodity
 
$
6,139

 
$
16,551

Total liabilities
 
$
6,139

 
$
16,551

____________________________________________
(1)
The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when relevant observable inputs are not available. There were no transfers between levels of the fair value hierarchy during the three and six months ended June 30, 2013. Forest’s policy is to recognize transfers between levels of the fair value hierarchy as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
(2)
Forest’s derivative assets and liabilities include commodity and interest rate derivatives (see Note 8 for more information on these instruments). Forest utilizes present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, Forest’s derivative instruments are included within the Level 2 fair value hierarchy.



13
Table of Contents

The fair values and carrying amounts of Forest’s financial instruments are summarized below as of the dates indicated.
 
 
June 30, 2013
 
 
 
 
 
Fair Value Measurements:
 
Carrying
Amount
 
Total Fair
Value(1)
 
Using Quoted Prices in
Active Markets for Identical Liabilities
(Level 1)
 
Using Significant Other
Observable Inputs
(Level 2)
 
(In Thousands)
Assets:
 

 
 

 
 

 
 

Derivative instruments
$
22,715

 
$
22,715

 
$
—

 
$
22,715

Liabilities:
 

 
 

 
 

 
 

Derivative instruments
6,139

 
6,139

 
—

 
6,139

Credit facility
130,000

 
130,000

 
—

 
130,000

7¼% senior notes due 2019
1,000,337

 
973,000

 
973,000

 
—

7½% senior notes due 2020
500,000

 
477,190

 
477,190

 
—

__________________________________________
(1)
Forest used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on quoted market prices. The carrying amount of the Credit Facility approximated fair value due to the short original maturities of the borrowings and because the borrowings bear interest at variable market rates. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 8 for more information on the derivative instruments.

 
December 31, 2012
 
 
 
 
 
Fair Value Measurements:
 
Carrying
Amount
 
Total Fair
Value(1)
 
Using Quoted Prices in
Active Markets for Identical Liabilities
(Level 1)
 
Using Significant Other
Observable Inputs
(Level 2)
 
(In Thousands)
Assets:
 

 
 

 
 
 
 
Derivative instruments
$
48,525

 
$
48,525

 
$
—

 
$
48,525

Liabilities:
 

 
 

 
 
 
 
Derivative instruments
16,551

 
16,551

 
—

 
16,551

Credit facility
65,000

 
65,000

 
—

 
65,000

8½% senior notes due 2014
296,723

 
321,000

 
321,000

 
—

7¼% senior notes due 2019
1,000,365

 
1,006,850

 
1,006,850

 
—

7½% senior notes due 2020
500,000

 
526,250

 
526,250

 
—

__________________________________________
(1)
Forest used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on quoted market prices. The carrying amount of the Credit Facility approximated fair value due to the short original maturities of the borrowings and because the borrowings bear interest at variable market rates. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 8 for more information on the derivative instruments.
   
(8) DERIVATIVE INSTRUMENTS
 
Commodity Derivatives
 
Forest periodically enters into commodity derivative instruments as an attempt to moderate the effects of wide fluctuations in commodity prices on Forest’s cash flow and to manage the exposure to commodity price risk. Forest’s commodity derivative instruments generally serve as effective economic hedges of commodity price exposure; however, Forest has elected not to designate its derivatives as hedging instruments for accounting purposes. As such, Forest recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the Condensed Consolidated Statement of Operations.
 


14
Table of Contents

The table below sets forth Forest’s outstanding commodity swaps as of June 30, 2013.
 
Commodity Swaps
 
 
Natural Gas
(NYMEX HH)
 
Oil
(NYMEX WTI)
Remaining Term
 
Bbtu
Per Day
 
Weighted
Average
Hedged Price
per MMBtu
 
Barrels
Per Day
 
Weighted
Average
Hedged Price
per Bbl
July 2013 - October 2013
 
145

 
$
3.99

 
4,000

 
$
95.53

November 2013 - December 2013
 
160

 
3.98

 
4,000

 
95.53

Calendar 2014
 
80

 
4.34

 
—

 
—


In connection with several natural gas and oil swaps entered into, Forest granted swaptions to the swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas and oil swaps. These swaptions grant the swap counterparties the option to enter into future swaps with Forest and may not be exercised until their expiration dates. The table below sets forth the outstanding swaptions as of June 30, 2013.
 
Commodity Options
 
 
 
 
Natural Gas (NYMEX HH)
 
Oil (NYMEX WTI)
Underlying Term
 
Option Expiration
 
Underlying
Bbtu
Per Day
 
Underlying
Hedged Price per
MMBtu
 
Underlying
Barrels Per Day
 
Underlying
Hedged Price per
Bbl
Gas Swaptions:
 
 
 
 
 
 
 
 
 
 
Calendar 2014
 
December 2013
 
30

 
$
4.50

 
—

 
$
—

Calendar 2014
 
December 2013
 
10

 
4.51

 
—

 
—

Oil Swaptions:
 
 
 
 
 
 
 
 
 
 
Calendar 2014
 
December 2013
 
—

 
—

 
4,000

 
100.00

Calendar 2014
 
December 2013
 
—

 
—

 
1,000

 
109.00

Calendar 2015
 
December 2014
 
—

 
—

 
3,000

 
100.00


Derivative Instruments Entered Into Subsequent to June 30, 2013

Subsequent to June 30, 2013, through August 6, 2013, Forest entered into the following derivative agreements:

Commodity Swaps
 
 
Oil (NYMEX WTI)
Swap Term
 
Barrels Per Day
 
Weighted Average
Hedged Price
per Bbl
July 2013 - December 2013
 
2,000

 
$
99.70

Calendar 2014
 
3,000

 
95.10


In addition to the swaps shown in the table above, Forest entered into 15 Bbtu per day of purchased natural gas swaps for the period September 2013 - December 2013 that directly offset 15 Bbtu per day of sold natural gas swaps. Additionally, Forest unwound the last two months of a Calendar 2013 natural gas swap covering 20 Bbtu per day at a hedged price of $4.03 per MMBtu. This brings Forest’s natural gas swap position for the period July 2013 - December 2013 to 133.4 Bbtu per day at a weighted average hedged price of $4.01 per MMBtu.


15
Table of Contents

Commodity Options
 
 
 
 
Oil (NYMEX WTI)
Underlying Term
 
Option Expiration
 
Underlying
Barrels Per Day
 
Underlying
Hedged Price per
Bbl
Oil Swaptions:
 
 
 
 
 
 
Calendar 2015(1)
 
December 2014
 
1,000

 
$
106.00

Calendar 2015(1)
 
December 2014
 
1,000

 
99.75

Calendar 2015(1)
 
December 2014
 
1,000

 
99.00

Oil Put Options:
 
 
 
 
 
 
Monthly Calendar 2014
 
Monthly Calendar 2014
 
2,000

 
70.00

____________________________________
(1)
In connection with entering into these oil swaptions, Forest terminated three of its existing oil swaptions with the counterparties for Calendar 2014. Two of the terminated swaptions covered 2,000 barrels per day with a hedged price per barrel of $100.00, and the third terminated swaption covered 1,000 barrels per day with a hedged price per barrel of $109.00.

Interest Rate Derivatives
 
Forest voluntarily terminated its interest rate swaps in June 2013 for proceeds of $11.4 million.

Fair Value and Gains and Losses
 
The table below summarizes the location and fair value amounts of Forest’s derivative instruments reported in the Condensed Consolidated Balance Sheets as of the dates indicated. These derivative instruments are not designated as hedging instruments for accounting purposes. For financial reporting purposes, Forest does not offset asset and liability fair value amounts recognized for derivative instruments with the same counterparty under its master netting arrangements. See “Credit Risk” below for more information regarding Forest’s master netting arrangements and gross and net presentation of derivative instruments. See also Note 7 for more information on the fair values of Forest’s derivative instruments.
 
 
June 30, 2013
 
December 31, 2012
 
(In Thousands)
Current assets:
 

 
 

Derivative instruments:
 

 
 

Commodity
$
17,211

 
$
28,690

Interest rate
—

 
11,500

Total current assets
$
17,211

 
$
40,190

Long-term assets:
 
 
 
Derivative instruments:
 
 
 
Commodity
$
5,504

 
$
6,775

Interest rate
—

 
1,560

Total long-term assets
$
5,504

 
$
8,335

Current liabilities:
 

 
 

Derivative instruments:
 

 
 

Commodity
$
3,829

 
$
9,347

Long-term liabilities:
 
 
 
Derivative instruments:
 
 
 
Commodity
$
2,310

 
$
7,204




16
Table of Contents

The table below summarizes the amount of derivative instrument gains and losses reported in the Condensed Consolidated Statements of Operations as realized and unrealized (gains) losses on derivative instruments, net, for the periods indicated. These derivative instruments are not designated as hedging instruments for accounting purposes.
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Commodity derivatives:
 

 
 

 
 

 
 

Realized losses (gains)
$
1,106

 
$
(31,067
)
 
$
(8,543
)
 
$
(52,395
)
Unrealized (gains) losses
(32,823
)
 
(2,126
)
 
2,338

 
(8,572
)
Interest rate derivatives:
 

 
 

 


 
 

Realized gains
(9,803
)
 
(2,837
)
 
(12,885
)
 
(5,721
)
Unrealized losses
9,910

 
2,015

 
13,060

 
3,149

Realized and unrealized gains on derivative instruments, net
$
(31,610
)
 
$
(34,015
)
 
$
(6,030
)
 
$
(63,539
)
 
Due to the volatility of oil and natural gas prices, the estimated fair values of Forest’s commodity derivative instruments are subject to large fluctuations from period to period. Forest has experienced the effects of these commodity price fluctuations in both the current period and prior periods and expects that volatility in commodity prices will continue.
 
Credit Risk
 
Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. (“ISDA”) Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes, with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties’ requirements and the specific types of derivatives to be transacted. As of June 30, 2013, all but one of Forest’s derivative counterparties are lenders, or affiliates of lenders, under the Credit Facility. The terms of the Credit Facility provide that any security granted by Forest thereunder shall also extend to and be available to those lenders that are counterparties to derivative transactions. None of these counterparties requires collateral beyond that already pledged under the Credit Facility. The remaining counterparty, a purchaser of Forest’s natural gas production, generally owes money to Forest and therefore does not require collateral under the ISDA Master Agreement and Schedule it has executed with Forest.

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

The majority of Forest’s derivative counterparties are financial institutions that are engaged in similar activities and have similar economic characteristics that, in general, could cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions. Forest does not require the posting of collateral for its benefit under its derivative agreements. However, the ISDA Master Agreements and Schedules generally contain netting provisions whereby if on any date amounts would otherwise be payable by each party to the other, then on such date, the party that owes the larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party’s obligations. These provisions generally apply to all derivative transactions, or all derivative transactions of the same type (e.g., commodity, interest rate, etc.), with the particular counterparty. If all counterparties failed, Forest would be exposed to a risk of loss equal to this net amount owed to Forest, the fair value of which was $18.2 million at June 30, 2013. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net obligations due to it under the derivative agreements. At June 30, 2013, Forest owed a net derivative liability to its counterparties, the fair value of which was $1.7 million. In the absence of netting provisions, at June 30, 2013, Forest would be exposed to a risk of loss of


17
Table of Contents

$22.7 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $6.1 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
 
June 30, 2013
 
December 31, 2012
 
(In Thousands)
Gross amounts of recognized assets
$
22,715

 
$
48,525

Gross amounts offset in the balance sheet
—

 
—

Net amounts of assets presented in the balance sheet
22,715

 
48,525

Gross amounts not offset in the balance sheet:
 
 
 
Derivative instruments
(4,484
)
 
(13,537
)
Cash collateral received
—

 
—

Net amount
$
18,231

 
$
34,988


 
Derivative Liabilities
 
June 30, 2013
 
December 31, 2012
 
(In Thousands)
Gross amounts of recognized liabilities
$
6,139

 
$
16,551

Gross amounts offset in the balance sheet
—

 
—

Net amounts of liabilities presented in the balance sheet
6,139

 
16,551

Gross amounts not offset in the balance sheet:
 
 
 
Derivative instruments
(4,484
)
 
(13,537
)
Cash collateral pledged
—

 
—

Net amount
$
1,655

 
$
3,014


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


18
Table of Contents

(9) COSTS, EXPENSES, AND OTHER
 
The table below sets forth the components of “Other, net” in the Condensed Consolidated Statements of Operations for the periods indicated.
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Accretion of asset retirement obligations
$
549

 
$
1,597

 
$
1,793

 
$
3,195

Loss on debt extinguishment
—

 
—

 
25,223

 
—

Legal proceeding liabilities
—

 
—

 
—

 
22,847

Other, net
1,044

 
1,858

 
3,397

 
4,333

 
$
1,593

 
$
3,455

 
$
30,413

 
$
30,375


Accretion of Asset Retirement Obligations

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

Loss on Debt Extinguishment

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

Legal Proceeding Liabilities

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled Forest Oil Corporation, et al. v. El Rucio Land & Cattle Company, Inc., et al., which occurred in Harris County, Texas. The third member of the arbitration panel dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration decision awards the claimant $22.8 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest is seeking to have this judgment reversed on appeal and believes it has meritorious arguments in support thereof. However, Forest is unable to predict the final outcome in this matter and has accrued a liability, which is classified within “Other liabilities” in the Condensed Consolidated Balance Sheet, of $23.6 million, which includes accrued interest, for this matter.

(10) COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders’ equity instead of net earnings (loss). Forest’s other comprehensive income during the three and six months ended June 30, 2013 consists of actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost.



19
Table of Contents

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

 
Before-Tax
 
Tax (Expense) / Benefit
 
Net-of-Tax
 
(In Thousands)
Three Months Ended June 30, 2013:
 
 
 
 
 
Defined benefit postretirement plans
 
 
 
 
 
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost
$
345

 
$
—

 
$
345

Other comprehensive income
$
345

 
$
—

 
$
345

Six Months Ended June 30, 2013:
 
 
 
 
 
Defined benefit postretirement plans
 
 
 
 
 
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost
$
687

 
$
—

 
$
687

Other comprehensive income
$
687

 
$
—

 
$
687


The change in the accumulated balance of other comprehensive income (loss) during the six months ended June 30, 2013 is as follows:
 
Accumulated
Other
Comprehensive
Income (Loss)(1)
 
(In Thousands)
Defined benefit postretirement plans
 
Balance at December 31, 2012
$
(20,514
)
 
 
Amounts reclassified from accumulated other comprehensive loss
687

Other comprehensive income
687

 
 
Balance at June 30, 2013
$
(19,827
)
____________________________________
(1)
All amounts are net of tax.

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

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

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

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

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

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

The following presents condensed consolidating financial information as of June 30, 2013 and December 31, 2012, and for the three and six months ended June 30, 2013 and 2012 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Eliminating entries presented are necessary to combine the entities.




20
Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
(In Thousands)
 
June 30, 2013
 
December 31, 2012
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
Current assets:
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
258

 
$
1

 
$
162

 
$
—

 
$
421

 
$
667

 
$
45

 
$
344

 
$
—

 
$
1,056

Accounts receivable
44,851

 
23,462

 
5,001

 
(844
)
 
72,470

 
33,979

 
27,969

 
6,393

 
(825
)
 
67,516

Other current assets
32,717

 
283

 
235

 
—

 
33,235

 
55,869

 
286

 
353

 
—

 
56,508

Total current assets
77,826

 
23,746

 
5,398

 
(844
)
 
106,126

 
90,515

 
28,300

 
7,090

 
(825
)
 
125,080

Property and equipment, at cost
8,244,692

 
1,451,251

 
177,982

 
—

 
9,873,925

 
8,439,898

 
1,416,364

 
182,070

 
—

 
10,038,332

Less accumulated depreciation, depletion, and amortization
7,007,346

 
1,193,741

 
174,416

 
—

 
8,375,503

 
6,937,606

 
1,173,332

 
173,156

 
—

 
8,284,094

Net property and equipment
1,237,346

 
257,510

 
3,566

 
—

 
1,498,422

 
1,502,292

 
243,032

 
8,914

 
—

 
1,754,238

Investment in subsidiaries
89,894

 
—

 
—

 
(89,894
)
 
—

 
68,048

 
—

 
—

 
(68,048
)
 
—

Goodwill
216,460

 
22,960

 
—

 
—

 
239,420

 
216,460

 
22,960

 
—

 
—

 
239,420

Due from subsidiaries
102,934

 
94,037

 
—

 
(196,971
)
 
—

 
116,602

 
83,983

 
—

 
(200,585
)
 
—

Deferred income taxes
102,881

 
—

 
36,106

 
(132,440
)
 
6,547

 
111,015

 
—

 
36,106

 
(132,440
)
 
14,681

Other assets
63,230

 
—

 
—

 
—

 
63,230

 
68,443

 
—

 
—

 
—

 
68,443

 
$
1,890,571

 
$
398,253

 
$
45,070

 
$
(420,149
)
 
$
1,913,745

 
$
2,173,375

 
$
378,275

 
$
52,110

 
$
(401,898
)
 
$
2,201,862

LIABILITIES AND
SHAREHOLDERS’
EQUITY
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Current liabilities:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Accounts payable and accrued liabilities
$
190,433

 
$
1,040

 
$
5,631

 
$
(844
)
 
$
196,260

 
$
157,404

 
$
2,133

 
$
6,074

 
$
(825
)
 
$
164,786

Other current liabilities
33,001

 
—

 
6,263

 
—

 
39,264

 
55,187

 
67

 
6,285

 
—

 
61,539

Total current liabilities
223,434

 
1,040

 
11,894

 
(844
)
 
235,524

 
212,591

 
2,200

 
12,359

 
(825
)
 
226,325

Long-term debt
1,630,337

 
—

 
—

 
—

 
1,630,337

 
1,862,088

 
—

 
—

 
—

 
1,862,088

Due to parent and subsidiaries
—

 
—

 
196,971

 
(196,971
)
 
—

 
—

 
—

 
200,585

 
(200,585
)
 
—

Deferred income taxes
—

 
132,440

 
—

 
(132,440
)
 
—

 
—

 
132,440

 
—

 
(132,440
)
 
—

Other liabilities
104,186

 
3,009

 
8,075

 
—

 
115,270

 
141,520

 
3,642

 
11,111

 
—

 
156,273

Total liabilities
1,957,957

 
136,489

 
216,940

 
(330,255
)
 
1,981,131

 
2,216,199

 
138,282

 
224,055

 
(333,850
)
 
2,244,686

Shareholders’ equity (deficit)
(67,386
)
 
261,764

 
(171,870
)
 
(89,894
)
 
(67,386
)
 
(42,824
)
 
239,993

 
(171,945
)
 
(68,048
)
 
(42,824
)
 
$
1,890,571

 
$
398,253

 
$
45,070

 
$
(420,149
)
 
$
1,913,745

 
$
2,173,375

 
$
378,275

 
$
52,110

 
$
(401,898
)
 
$
2,201,862








21
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In Thousands)
 
Three Months Ended June 30,
 
2013
 
2012
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
Oil, natural gas, and natural gas liquids sales
$
92,124

 
$
24,735

 
$
(73
)
 
$
—

 
$
116,786

 
$
99,798

 
$
35,485

 
$
411

 
$
—

 
$
135,694

Interest and other
131

 
433

 
1

 
(537
)
 
28

 
909

 
(1,387
)
 
—

 
515

 
37

Equity earnings in subsidiaries
14,162

 
—

 
—

 
(14,162
)
 
—

 
9,195

 
—

 
—

 
(9,195
)
 
—

Total revenues
106,417

 
25,168

 
(72
)
 
(14,699
)
 
116,814

 
109,902

 
34,098

 
411

 
(8,680
)
 
135,731

Costs, expenses, and other:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Lease operating expenses
15,837

 
3,326

 
4

 
—

 
19,167

 
22,153

 
4,891

 
90

 
—

 
27,134

Other production expenses
7,473

 
656

 
(2
)
 
—

 
8,127

 
10,594

 
(86
)
 
47

 
—

 
10,555

General and administrative
12,562

 
224

 
328

 
—

 
13,114

 
15,595

 
620

 
206

 
—

 
16,421

Depreciation, depletion, and amortization
33,116

 
9,560

 
1,128

 
—

 
43,804

 
53,534

 
19,015

 
438

 
—

 
72,987

Ceiling test write-down of oil and natural gas properties
—

 
—

 
—

 
—

 
—

 
348,976

 
—

 
—

 
—

 
348,976

Interest expense
29,391

 
36

 
502

 
(537
)
 
29,392

 
34,316

 
(1,523
)
 
1,009

 
515

 
34,317

Realized and unrealized gains on derivative instruments, net
(25,734
)
 
(5,827
)
 
(49
)
 
—

 
(31,610
)
 
(26,320
)
 
(7,604
)
 
(91
)
 
—

 
(34,015
)
Other, net
665

 
95

 
833

 
—

 
1,593

 
1,335

 
107

 
2,013

 
—

 
3,455

Total costs, expenses, and other
73,310

 
8,070

 
2,744

 
(537
)
 
83,587

 
460,183

 
15,420

 
3,712

 
515

 
479,830

Earnings (loss) before income taxes
33,107

 
17,098

 
(2,816
)
 
(14,162
)
 
33,227

 
(350,281
)
 
18,678

 
(3,301
)
 
(9,195
)
 
(344,099
)
Income tax (benefit) expense
(332
)
 
175

 
(55
)
 
—

 
(212
)
 
160,892

 
7,489

 
(1,307
)
 
—

 
167,074

Net earnings (loss)
$
33,439

 
$
16,923

 
$
(2,761
)
 
$
(14,162
)
 
$
33,439

 
$
(511,173
)
 
$
11,189

 
$
(1,994
)
 
$
(9,195
)
 
$
(511,173
)
Comprehensive income (loss)
$
33,784

 
$
16,923

 
$
(2,761
)
 
$
(14,162
)
 
$
33,784

 
$
(510,987
)
 
$
11,189

 
$
(1,994
)
 
$
(9,195
)
 
$
(510,987
)






















22
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (Continued)
(Unaudited)
(In Thousands)
 
Six Months Ended June 30,
 
2013
 
2012
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
Oil, natural gas, and natural gas liquids sales
$
184,661

 
$
49,765

 
$
402

 
$
—

 
$
234,828

 
$
206,621

 
$
87,091

 
$
883

 
$
—

 
$
294,595

Interest and other
356

 
835

 
1

 
(1,032
)
 
160

 
1,687

 
572

 
—

 
(2,190
)
 
69

Equity earnings in subsidiaries
18,308

 
—

 
—

 
(18,308
)
 
—

 
(7,599
)
 
—

 
—

 
7,599

 
—

Total revenues
203,325

 
50,600

 
403

 
(19,340
)
 
234,988

 
200,709

 
87,663

 
883

 
5,409

 
294,664

Costs, expenses, and other:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Lease operating expenses
33,782

 
6,501

 
88

 
—

 
40,371

 
45,972

 
8,579

 
190

 
—

 
54,741

Other production expenses
13,394

 
191

 
38

 
—

 
13,623

 
24,391

 
1,191

 
98

 
—

 
25,680

General and administrative
31,693

 
894

 
541

 
—

 
33,128

 
29,959

 
1,351

 
495

 
—

 
31,805

Depreciation, depletion, and amortization
70,678

 
20,408

 
1,261

 
—

 
92,347

 
101,403

 
37,683

 
871

 
—

 
139,957

Ceiling test write-down of oil and natural gas properties
—

 
—

 
—

 
—

 
—

 
348,976

 
—

 
34,817

 
—

 
383,793

Interest expense
65,519

 
68

 
965

 
(1,032
)
 
65,520

 
67,708

 
188

 
2,003

 
(2,190
)
 
67,709

Realized and unrealized gains on derivative instruments, net
(4,869
)
 
(1,152
)
 
(9
)
 
—

 
(6,030
)
 
(50,927
)
 
(12,451
)
 
(161
)
 
—

 
(63,539
)
Other, net
27,675

 
212

 
2,526

 
—

 
30,413

 
26,567

 
197

 
3,611

 
—

 
30,375

Total costs, expenses, and other
237,872

 
27,122

 
5,410

 
(1,032
)
 
269,372

 
594,049

 
36,738

 
41,924

 
(2,190
)
 
670,521

Earnings (loss) before income taxes
(34,547
)
 
23,478

 
(5,007
)
 
(18,308
)
 
(34,384
)
 
(393,340
)
 
50,925

 
(41,041
)
 
7,599

 
(375,857
)
Income tax (benefit) expense
(38
)
 
207

 
(44
)
 
—

 
125

 
150,506

 
19,917

 
(2,434
)
 
—

 
167,989

Net earnings (loss)
$
(34,509
)
 
$
23,271

 
$
(4,963
)
 
$
(18,308
)
 
$
(34,509
)
 
$
(543,846
)
 
$
31,008

 
$
(38,607
)
 
$
7,599

 
$
(543,846
)
Comprehensive income (loss)
$
(33,822
)
 
$
23,271

 
$
(4,963
)
 
$
(18,308
)
 
$
(33,822
)
 
$
(543,473
)
 
$
31,008

 
$
(38,607
)
 
$
7,599

 
$
(543,473
)




23
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
(In Thousands)
 
Six Months Ended June 30,
 
2013
 
2012
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidated
 
Parent
Company
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidated
Operating activities:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Net earnings (loss)
$
(52,817
)
 
$
23,271

 
$
(4,963
)
 
$
(34,509
)
 
$
(536,247
)
 
$
31,008

 
$
(38,607
)
 
$
(543,846
)
Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Depreciation, depletion, and amortization
70,678

 
20,408

 
1,261

 
92,347

 
101,403

 
37,683

 
871

 
139,957

Deferred income tax
—

 
—

 
—

 
—

 
150,397

 
19,917

 
(2,434
)
 
167,880

Unrealized losses (gains) on derivative instruments, net
14,961

 
433

 
4

 
15,398

 
(3,649
)
 
(1,751
)
 
(23
)
 
(5,423
)
Ceiling test write-down of oil and natural gas properties
—

 
—

 
—

 
—

 
348,976

 
—

 
34,817

 
383,793

Loss on debt extinguishment
25,223

 
—

 
—

 
25,223

 
—

 
—

 
—

 
—

Other, net
11,384

 
205

 
(2,207
)
 
9,382

 
17,896

 
187

 
(993
)
 
17,090

Changes in operating assets and liabilities:
 

 
 
 
 
 
 

 
 

 
 
 
 

 
 

Accounts receivable
(10,086
)
 
4,507

 
1,411

 
(4,168
)
 
11,522

 
7,641

 
(86
)
 
19,077

Other current assets
(390
)
 
3

 
118

 
(269
)
 
2,360

 
(1
)
 
(54
)
 
2,305

Accounts payable and accrued liabilities
18,865

 
(541
)
 
(368
)
 
17,956

 
(19,765
)
 
(1,254
)
 
418

 
(20,601
)
Accrued interest and other
(10,697
)
 
(187
)
 
(64
)
 
(10,948
)
 
16,210

 
96

 
(114
)
 
16,192

Net cash provided (used) by operating activities
67,121

 
48,099

 
(4,808
)
 
110,412

 
89,103

 
93,526

 
(6,205
)
 
176,424

Investing activities:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Capital expenditures for property and equipment
(169,741
)
 
(35,699
)
 
(774
)
 
(206,214
)
 
(312,214
)
 
(80,990
)
 
(7,487
)
 
(400,691
)
Proceeds from sales of assets
338,975

 
—

 
2

 
338,977

 
1,102

 
—

 
—

 
1,102

Net cash provided (used) by investing activities
169,234

 
(35,699
)
 
(772
)
 
132,763

 
(311,112
)
 
(80,990
)
 
(7,487
)
 
(399,589
)
Financing activities:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Proceeds from bank borrowings
320,000

 
—

 
—

 
320,000

 
443,000

 
—

 
—

 
443,000

Repayments of bank borrowings
(255,000
)
 
—

 
—

 
(255,000
)
 
(200,000
)
 
—

 
—

 
(200,000
)
Redemption of senior notes
(321,327
)
 
—

 
—

 
(321,327
)
 
—

 
—

 


 
—

Change in bank overdrafts
13,932

 
(457
)
 
48

 
13,523

 
(20,445
)
 
(341
)
 
120

 
(20,666
)
Net activity in investments in subsidiaries
6,637

 
(11,987
)
 
5,350

 
—

 
(203
)
 
(12,194
)
 
12,397

 
—

Other, net
(1,006
)
 
—

 
—

 
(1,006
)
 
(1,501
)
 
—

 
—

 
(1,501
)
Net cash (used) provided by financing activities
(236,764
)
 
(12,444
)
 
5,398

 
(243,810
)
 
220,851

 
(12,535
)
 
12,517

 
220,833

Net (decrease) increase in cash and cash equivalents
(409
)
 
(44
)
 
(182
)
 
(635
)
 
(1,158
)
 
1

 
(1,175
)
 
(2,332
)
Cash and cash equivalents at beginning of period
667

 
45

 
344

 
1,056

 
1,734

 
1

 
1,277

 
3,012

Cash and cash equivalents at end of period
$
258

 
$
1

 
$
162

 
$
421

 
$
576

 
$
2

 
$
102

 
$
680






24
Table of Contents

Item 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
OVERVIEW
 
All expectations, forecasts, assumptions, and beliefs about our future financial results, condition, operations, strategic plans, and performance are forward-looking statements, as described in more detail under the heading “Forward-Looking Statements” below. Our actual results may differ materially because of a number of risks and uncertainties. Historical statements made herein are accurate only as of the date of filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”), and may be relied upon only as of that date. The following discussion and analysis should be read in conjunction with Forest’s Condensed Consolidated Financial Statements and the Notes thereto, the information included or incorporated by reference under the headings “Forward-Looking Statements” and “Risk Factors” below, and the information included or incorporated by reference in Forest’s 2012 Annual Report on Form 10-K under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Unless the context indicates otherwise, all references in this document to “Forest,” “the Company,” “we,” “our,” “ours,” and “us” refer to Forest Oil Corporation and its consolidated subsidiaries.
 
Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in North America. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. We currently conduct our operations in one material geographical segment: the United States. Our core operational areas are in the Eagle Ford Shale in South Texas, the East Texas / North Louisiana Area, and the Texas Panhandle Area.

Recent Events

In October 2012, we entered into an agreement to sell all of our oil and natural gas properties located in South Louisiana for $220 million in cash. This transaction closed in November 2012, and we have received net proceeds of $211 million, after customary purchase price adjustments, through June 30, 2013. In January 2013, we entered into an agreement to sell all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford Shale oil properties, for $325 million in cash. This transaction closed in February 2013, and we received net proceeds of $321 million, after customary purchase price adjustments, through June 30, 2013. We used the proceeds from these property sales to reduce our indebtedness. These property sales affect the comparability of the results of our operations between the three and six months ended June 30, 2013 and the three and six months ended June 30, 2012 presented herein.

In April 2013, we entered into an agreement with a third-party for the future development of our Eagle Ford Shale acreage in Gonzales County, Texas. Under the terms of the agreement, the third-party will pay a $90 million drilling carry in the form of future drilling and completion services and related development capital in exchange for a 50% working interest in our Eagle Ford Shale acreage position. Upon completion of the phased contribution of the drilling carry, Forest and the third-party will participate in future drilling on a 50/50 basis. The agreement applies to wells spud on or subsequent to November 28, 2012, none of which had been placed on production prior to April 1, 2013, and we retained all of our interests in wells and production that were spud prior to November 28, 2012. We are the operator of the drilling program and currently expect that the drilling carry will be fully realized by mid-2014.

In July 2013, we announced that we will initiate a marketed process to pursue the potential sale of our oil and natural gas properties located in the Texas Panhandle Area. If the sale of these assets is completed, we intend to use the proceeds to reduce our indebtedness.

RESULTS OF OPERATIONS

For the three and six months ended June 30, 2013, we recognized net earnings of $33 million and a net loss of $35 million, respectively, compared to net losses of $511 million and $544 million for the three and six months ended June 30, 2012, respectively. The net earnings for the three months ended June 30, 2013 included a $23 million unrealized gain on derivative instruments whereas the net loss for the six months ended June 30, 2013 included a $15 million unrealized loss on derivative instruments, a $25 million loss on the early termination of debt, and $7 million in severance-related expenses associated with the sale of our South Texas oil and natural gas properties. The net losses in the 2012 periods were primarily due to ceiling test write-downs and the related increases in valuation allowances recorded on our deferred tax assets. We recorded a $35 million ceiling test write-down of our Italian natural gas properties in the first quarter of 2012 and a $349 million ceiling test write-down of our U.S. oil and natural gas properties in the second quarter of 2012. Primarily in connection with these write-downs, we recorded additional deferred income tax expense of $290 million and $303 million for the three and six


25
Table of Contents

months ended June 30, 2012, respectively, as a result of increasing the valuation allowances on our deferred tax assets. See “Ceiling Test Write-Down of Oil and Natural Gas Properties” below for more information regarding our ceiling test write-downs.

Adjusted EBITDA, which excludes the effects of unrealized gains and losses on derivative instruments, ceiling test write-downs, and other items, was $88 million and $182 million for the three and six months ended June 30, 2013, respectively, as compared to $122 million and $247 million for the three and six months ended June 30, 2012, respectively. The $34 million and $65 million decreases between the corresponding three and six month periods, respectively, were primarily due to the sale of oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively, and a decrease in realized gains on derivative instruments. Adjusted EBITDA is a performance measure that is not calculated in accordance with generally accepted accounting principles (“GAAP”); see “—Reconciliation of Non-GAAP Measure” at the end of this Item 2 for a reconciliation of Adjusted EBITDA to reported net earnings (loss), which is the most directly comparable financial measure calculated and presented in accordance with GAAP.

Management’s analysis of the individual components of the changes in our quarterly and year-to-date results follows.

Oil, Natural Gas, and Natural Gas Liquids Volumes, Revenues, and Prices
 
Oil, natural gas, and natural gas liquids sales volumes, revenues, and average sales prices for the three and six months ended June 30, 2013 and 2012 are set forth in the table below.

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013

2012
 
2013

2012
Sales volumes:
 

 
 

 
 

 
 

Oil (MBbls)
601

 
758

 
1,160

 
1,525

Natural gas (MMcf)
11,406

 
20,872

 
25,738

 
41,765

NGLs (MBbls)
694

 
850

 
1,392

 
1,716

Totals (MMcfe)
19,176

 
30,520

 
41,050

 
61,211

Revenues (in thousands):
 
 
 
 
 
 
 
Oil
$
56,316

 
$
72,291

 
$
110,278

 
$
151,742

Natural gas
41,161

 
38,693

 
83,819

 
86,721

NGLs
19,309

 
24,710

 
40,731

 
56,132

Totals
$
116,786

 
$
135,694

 
$
234,828

 
$
294,595

Average sales price per unit:
 

 
 

 
 

 
 

Oil ($/Bbl)
$
93.70

 
$
95.37

 
$
95.07

 
$
99.50

Natural gas ($/Mcf)
3.61

 
1.85

 
3.26

 
2.08

NGLs ($/Bbl)
27.82

 
29.07

 
29.26

 
32.71

Totals ($/Mcfe)
$
6.09

 
$
4.45

 
$
5.72

 
$
4.81


Our equivalent sales volumes for the three and six months ended June 30, 2013 were 19.2 Bcfe and 41.1 Bcfe, respectively, compared to 30.5 Bcfe and 61.2 Bcfe for the three and six months ended June 30, 2012, respectively. The decreases in equivalent sales volumes in the 2013 periods as compared to the 2012 periods were primarily due to divestitures of oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively. Revenues from oil, natural gas, and NGLs were $117 million in the second quarter of 2013 compared to $136 million in the second quarter of 2012. The $19 million decrease was primarily a result of the decrease in equivalent sales volumes due to the aforementioned divestitures. The decrease due to the decline in equivalent sales volumes was partially offset by a 37% increase in the average sales price per Mcfe between the two periods from $4.45 per Mcfe in the second quarter of 2012 to $6.09 per Mcfe in the second quarter of 2013.

Revenues from oil, natural gas, and NGLs were $235 million in the first six months of 2013 compared to $295 million in the first six months of 2012. The $60 million decrease was primarily a result of the decrease in equivalent sales volumes due to the aforementioned divestitures. The decrease due to the decline in equivalent sales volumes was partially offset by a 19% increase in the average sales price per Mcfe between the two periods from $4.81 per Mcfe in the first six months of 2012 to $5.72 per Mcfe in the first six months of 2013.



26
Table of Contents

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

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
Oil:
 
 
 
 
 
 
 
Average sales price ($/Bbl)
$
93.70

 
$
95.37

 
$
95.07

 
$
99.50

Effects of commodity derivatives ($/Bbl)
.79

 
2.84

 
.78

 
.01

Average realized price ($/Bbl)
$
94.49

 
$
98.21

 
$
95.84

 
$
99.51

 
 
 
 
 
 
 
 
Natural gas:
 
 
 
 
 
 
 
Average sales price ($/Mcf)
$
3.61

 
$
1.85

 
$
3.26

 
$
2.08

Effects of commodity derivatives ($/Mcf)
(.14
)
 
1.34

 
.30

 
1.26

Average realized price ($/Mcf)
$
3.47

 
$
3.20

 
$
3.55

 
$
3.33

 
 
 
 
 
 
 
 
NGLs:
 
 
 
 
 
 
 
Average sales price ($/Bbl)
$
27.82

 
$
29.07

 
$
29.26

 
$
32.71

Effects of commodity derivatives ($/Bbl)
—

 
.99

 
—

 
(.07
)
Average realized price ($/Bbl)
$
27.82

 
$
30.06

 
$
29.26

 
$
32.64

 
 
 
 
 
 
 
 
Totals:
 
 
 
 
 
 
 
Average sales price ($/Mcfe)
$
6.09

 
$
4.45

 
$
5.72

 
$
4.81

Effects of commodity derivatives ($/Mcfe)
(.06
)
 
1.02

 
.21

 
.86

Average realized price ($/Mcfe)
$
6.03

 
$
5.46

 
$
5.93

 
$
5.67


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

Production Expense
 
The table below sets forth the detail of production expense for the periods indicated.
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands, Except Per Mcfe Data)
Production expense:
 

 
 

 
 

 
 

Lease operating expenses
$
19,167

 
$
27,134

 
$
40,371

 
$
54,741

Production and property taxes
5,029

 
6,940

 
7,245

 
18,093

Transportation and processing costs
3,098

 
3,615

 
6,378

 
7,587

Production expense
$
27,294

 
$
37,689

 
$
53,994

 
$
80,421

Production expense per Mcfe:
 

 
 

 
 

 
 

Lease operating expenses
$
1.00

 
$
.89

 
$
.98

 
$
.89

Production and property taxes
.26

 
.23

 
.18

 
.30

Transportation and processing costs
.16

 
.12

 
.16

 
.12

Production expense per Mcfe
$
1.42

 
$
1.23

 
$
1.32

 
$
1.31

 


27
Table of Contents

Lease Operating Expenses
 
Lease operating expenses in the second quarter of 2013 were $19 million, or $1.00 per Mcfe, compared to $27 million, or $.89 per Mcfe, in the second quarter of 2012. Lease operating expenses in the first six months of 2013 were $40 million, or $.98 per Mcfe, compared to $55 million, or $.89 per Mcfe, in the first six months of 2012. Lease operating expenses decreased $8 million and $14 million in the three and six month periods ended June 30, 2013 compared to the corresponding periods in 2012, respectively, primarily due to the oil and natural gas property divestitures that occurred in November 2012 and February 2013.
 
Production and Property Taxes
 
Production and property taxes, consisting primarily of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 4.3% and 5.1% of oil, natural gas, and NGL revenues for the three-month periods ended June 30, 2013 and 2012, respectively, and 3.1% and 6.1% of oil, natural gas, and NGL revenues for the six-month periods ended June 30, 2013 and 2012, respectively. The decreases in production and property taxes as a percentage of revenues in the three and six month periods ended June 30, 2013 were due to reduced severance tax rates on several wells in the Texas Panhandle Area. Normal fluctuations occur in this percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, and changes in the assessed values of oil and gas properties and equipment for purposes of ad valorem taxes.
 
Transportation and Processing Costs
 
Transportation and processing costs in the second quarter of 2013 were $3 million, or $.16 per Mcfe, compared to $4 million, or $.12 per Mcfe, in the second quarter of 2012. Transportation and processing costs in the first six months of 2013 were $6 million, or $.16 per Mcfe, compared to $8 million, or $.12 per Mcfe, in the first six months of 2012.

General and Administrative Expense
 
The table below sets forth the components of general and administrative expense for the periods indicated.
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Stock-based compensation costs
$
4,881

 
$
7,326

 
$
12,105

 
$
13,373

Stock-based compensation costs capitalized
(1,631
)
 
(1,619
)
 
(4,595
)
 
(4,216
)
 
3,250

 
5,707

 
7,510

 
9,157

 
 
 
 
 
 
 
 
Other general and administrative costs
16,331

 
17,860

 
41,419

 
38,748

Other general and administrative costs capitalized
(6,467
)
 
(7,146
)
 
(15,801
)
 
(16,100
)
 
9,864

 
10,714

 
25,618

 
22,648

 
 
 
 
 
 
 
 
General and administrative expense
$
13,114

 
$
16,421

 
$
33,128

 
$
31,805


General and administrative expense was $13 million in the second quarter of 2013, compared to $16 million in the second quarter of 2012, and was $33 million in the first six months of 2013, compared to $32 million in the first six months of 2012. For the first six months of 2013, other general and administrative costs include $8 million ($6 million net of capitalized amounts) and stock-based compensation costs include $2 million ($1 million net of capitalized amounts) in employee severance-related costs incurred due to the disposition of the South Texas oil and natural gas properties during the first quarter of 2013. General and administrative expense in the second quarter of 2012 includes $5 million ($4 million net of capitalized amounts) in accelerated stock-based compensation costs and $2 million ($2 million net of capitalized amounts) in accrued severance costs, which are both related to the termination of our former chief executive officer. The percentage of general and administrative costs capitalized under the full cost method of accounting ranged from 35% to 39% in the periods presented.



28
Table of Contents

Depreciation, Depletion, and Amortization
 
Depreciation, depletion, and amortization expense (“DD&A”) in the second quarter of 2013 was $44 million, or $2.28 per Mcfe, compared to $73 million, or $2.39 per Mcfe, in the second quarter of 2012. For the first six months of 2013, DD&A was $92 million, or $2.25 per Mcfe, compared to $140 million, or $2.29 per Mcfe, in the first six months of 2012.

Ceiling Test Write-Down of Oil and Natural Gas Properties

In the second quarter of 2012, we recorded a ceiling test write-down of our United States cost center pursuant to the ceiling test limitation prescribed by the SEC for companies using the full cost method of accounting. The write-down totaled $349 million and was primarily a result of a significant decline in natural gas prices during that quarter. Although we did not incur a ceiling test write-down at March 31, 2013 or June 30, 2013, additional write-downs of the United States cost center may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month natural gas and oil prices used in the calculation of the present value of future net revenue from estimated production of proved oil and gas reserves decline compared to prices used as of June 30, 2013, unproved property values decrease, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center.

In April 2012, an Italian regional regulatory body denied approval of an environmental impact assessment associated with our proposal to commence natural gas production from wells that we drilled and completed in 2007. We are currently appealing the region’s denial; however, until the region’s denial is reversed or overturned, we determined that we could no longer conclude with reasonable certainty that our Italian natural gas reserves are producible. Accordingly, in the first quarter of 2012, we reclassified the Italian reserves from proved to probable and recorded a ceiling test write-down of our Italian cost center of $35 million.

Interest Expense
 
The table below sets forth interest expense for the periods indicated.
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Interest costs
$
30,315

 
$
36,185

 
$
66,634

 
$
71,806

Interest costs capitalized
(923
)
 
(1,868
)
 
(1,114
)
 
(4,097
)
Interest expense
$
29,392

 
$
34,317

 
$
65,520

 
$
67,709

 
Interest expense was $29 million and $34 million for the three months ended June 30, 2013 and 2012, respectively. Interest expense was $66 million and $68 million for the six months ended June 30, 2013 and 2012, respectively. The decreases of $5 million and $2 million in the comparable three and six month periods, respectively, were primarily attributable to the redemption of $300 million of 8½% senior notes in October 2012, the redemption of the remaining $300 million of 8½% senior notes in March 2013, and decreased borrowings outstanding under our credit facility during 2013, partially offset by interest costs on the $500 million of 7½% senior notes issued in September 2012 and lower capitalized interest in 2013. Interest costs capitalized relate to our investments in significant unproved acreage positions that are under development. See “Liquidity and Capital Resources—Bank Credit Facility” below for more information regarding our credit facility.




29
Table of Contents

Realized and Unrealized Gains and Losses on Derivative Instruments

The table below sets forth realized and unrealized gains and losses on derivative instruments recognized under “Costs, expenses, and other” in our Condensed Consolidated Statements of Operations for the periods indicated. See Note 7 and Note 8 to the Condensed Consolidated Financial Statements for more information on our derivative instruments.
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Realized (gains) losses on derivative instruments, net:
 

 
 

 
 

 
 

Oil
$
(473
)
 
$
(2,155
)
 
$
(901
)
 
$
(15
)
Natural gas
1,579

 
(28,067
)
 
(7,642
)
 
(52,508
)
NGLs
—

 
(845
)
 
—

 
128

Interest(1)
(9,803
)
 
(2,837
)
 
(12,885
)
 
(5,721
)
Subtotal realized gains on derivative instruments, net
(8,697
)
 
(33,904
)
 
(21,428
)
 
(58,116
)
Unrealized (gains) losses on derivative instruments, net:
 

 
 

 
 

 
 

Oil
(5,736
)
 
(26,918
)
 
(6,044
)
 
(9,519
)
Natural gas
(27,087
)
 
30,987

 
8,382

 
10,467

NGLs
—

 
(6,195
)
 
—

 
(9,520
)
Interest
9,910

 
2,015

 
13,060

 
3,149

Subtotal unrealized (gains) losses on derivative instruments, net
(22,913
)
 
(111
)
 
15,398

 
(5,423
)
Realized and unrealized gains on derivative instruments, net
$
(31,610
)
 
$
(34,015
)
 
$
(6,030
)
 
$
(63,539
)
____________________________________________
(1)
In June 2013, we voluntarily terminated our fixed-to-floating interest rate swaps under which we had swapped $500 million in notional amount at an 8.5% fixed rate for an equal notional amount at a weighted-average interest rate equal to the 1-month LIBOR plus approximately 5.9%. As part of this termination, we received proceeds of $11 million, which are included in realized gains on derivative instruments for the six months ended June 30, 2013.

Other, Net
 
The table below sets forth the components of “Other, net” for the periods indicated.
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Accretion of asset retirement obligations
$
549

 
$
1,597

 
$
1,793

 
$
3,195

Loss on debt extinguishment
—

 
—

 
25,223

 
—

Legal proceeding liabilities
—

 
—

 
—

 
22,847

Other, net
1,044

 
1,858

 
3,397

 
4,333

 
$
1,593

 
$
3,455

 
$
30,413

 
$
30,375

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



30
Table of Contents

Income Tax
 
The table below sets forth the current and deferred components of income tax and the effective income tax rates for the periods indicated.
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands, Except Percentages)
Current income tax
$
(212
)
 
$
327

 
$
125

 
$
109

Deferred income tax
—

 
166,747

 
—

 
167,880

Total income tax (benefit) expense
$
(212
)
 
$
167,074

 
$
125

 
$
167,989

Effective income tax rate
(.6
)%
 
(49
)%
 
(.4
)%
 
(45
)%
 
Our effective income tax rates were (.6)% and (.4)% for the three and six months ended June 30, 2013, respectively, and (49)% and (45)% for the three and six months ended June 30, 2012, respectively. The significant differences between our blended federal and state statutory income tax rate of 36% and our effective income tax rates were primarily due to changes in valuation allowances placed against our deferred tax assets. See Note 6 to the Condensed Consolidated Financial Statements for more information regarding our income tax valuation allowance.

LIQUIDITY AND CAPITAL RESOURCES

Our exploration, development, and acquisition activities require us to make significant operating and capital expenditures (see “Capital Expenditures”). Historically, we have used cash flow from operations and our bank credit facility as our primary sources of liquidity. To fund large transactions, such as acquisitions and debt refinancing transactions, we have looked to the private and public capital markets as another source of financing and, as market conditions have permitted, we have engaged in asset monetization transactions.
 
Changes in the market prices for oil, natural gas, and NGLs directly impact our level of cash flow generated from operations. We employ a commodity hedging strategy in an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of August 6, 2013, we had hedged, via commodity swaps, approximately 64 Bcfe of our total projected 2013 production and approximately 36 Bcfe of our total projected 2014 production, excluding the volumes underlying outstanding unexercised commodity swaptions and oil put options. This level of hedging will provide a measure of certainty with respect to the cash flow that we will receive for a portion of our future production. However, these hedging activities may result in reduced income or even financial losses to us. In the future, we may determine to increase or decrease our hedging positions. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” below for more information on our derivative instruments.
 
As noted above, the other primary source of liquidity is our credit facility, which currently has a borrowing base of $900 million. The borrowing base is subject to redetermination from time to time as discussed below under “Bank Credit Facility.” This facility is used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facility is secured by a portion of our assets and matures in June 2016. The credit facility contains a covenant that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.50 to 1.00 at any time. Depending on our overall level of indebtedness, this covenant may limit our ability to borrow funds as needed under our credit facility. Our ratio of total debt outstanding to EBITDA for the twelve-month period ended June 30, 2013, as calculated in accordance with the credit facility, was 4.37. We had $130 million and $148 million of borrowings outstanding under the credit facility as of June 30, 2013 and August 1, 2013, respectively. The covenant described above would currently prevent us from borrowing the full amount of our remaining borrowing base. See “Bank Credit Facility” below for further details regarding the credit facility.
 
The public and private capital markets have served as our primary source of financing to fund large acquisitions and other exceptional transactions, such as debt refinancings. In the past, we have issued debt and equity in both the public and private capital markets. Our ability to access the debt and equity capital markets on economic terms is affected by general economic conditions, the domestic and global financial markets, the credit ratings assigned to our debt by independent credit rating agencies, our operational and financial performance, the value and performance of our equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control.



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We also have engaged in asset dispositions as a means of generating additional cash to fund expenditures and enhance our financial flexibility. For example, in November 2012, we sold all of our oil and natural gas properties located in South Louisiana for net proceeds of $211 million. Additionally, in February 2013 we sold all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford Shale oil properties, for net proceeds of $321 million, which we used in March 2013 to redeem the remaining $300 million in principal amount of 8½% senior notes due 2014. In addition, as discussed in “Overview—Recent Events,” we have entered into an agreement with a third-party pursuant to which the third-party is funding a portion of the drilling and other development costs relating to certain Eagle Ford Shale acreage, and we have initiated a marketed process to pursue the potential sale of our oil and natural gas properties located in the Texas Panhandle Area. There can be no assurance that such a sale can be completed on the terms or in the time frame we expect or at all.

We believe that our cash flows provided by operating activities and funds available under the credit facility will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures, and our contractual obligations. If our revenue and cash flow decrease as a result of lower-than-expected production or a decline in commodity prices, and we are unable to sufficiently reduce our total debt through asset divestitures, we may be compelled to seek a waiver or amendment to the credit facility, allowing us to temporarily maintain a total debt-to-EBITDA ratio in excess of 4.50 to 1.00.

Bank Credit Facility
 
On June 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the ‘‘Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A. (the “Administrative Agent”) consisting of a $1.5 billion credit facility maturing in June 2016. The size of the Credit Facility may be increased by $300 million, to a total of $1.8 billion, upon agreement between us and the applicable lenders.
 
Our availability under the Credit Facility is governed by a borrowing base. As of June 30, 2013, the borrowing base under the Credit Facility was $900 million. The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil and 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. 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 was reaffirmed at $900 million in April 2013 and the next scheduled semi-annual redetermination of the borrowing base will occur on or about November 1, 2013.

The borrowing base is also subject to automatic adjustments if certain events occur, such as if we or any of our Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that we or any of our Restricted Subsidiaries may issue to refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if we or any of our Restricted Subsidiaries sell oil and natural gas properties included in the borrowing base, as applicable, having a fair market value in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount either (i) equal to the percentage of the borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by us and the required lenders. The sale of our South Texas properties resulted in a $170 million reduction to the borrowing base when the transaction closed in February 2013, bringing the borrowing base to $900 million. See Note 5 to the Condensed Consolidated Financial Statements for more information regarding this divestiture.

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



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

(i)
the greatest of (a) the prime rate announced by JPMorgan Chase Bank, N.A., (b) the federal funds effective rate from time to time plus ½ of 1%, and (c) the one-month rate applicable to dollar deposits in the London interbank market for one, two, three or six months (as selected by us) (the “LIBO Rate”) plus 1%, plus, in the case of each of clauses (a), (b), and (c), 50 to 150 basis points depending on borrowing base utilization; or
 
(ii)
the LIBO Rate as adjusted for statutory reserve requirements (the “Adjusted LIBO Rate”), plus 150 to 250 basis points, depending on borrowing base utilization. 

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant. The Credit Facility provides that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.50 to 1.00 at any time. Our ratio of total debt outstanding to EBITDA for the twelve-month period ended June 30, 2013, as calculated in accordance with the Credit Facility, was 4.37. We expect to continue to meet this covenant by maintaining our capital expenditures at levels that approximate our cash flows from operating activities and by using proceeds from the sale of assets to reduce debt.

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

At June 30, 2013, there were outstanding borrowings of $130 million under the Credit Facility at a weighted average interest rate of 1.8%, and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $768 million. At August 1, 2013, there were outstanding borrowings of $148 million under the Credit Facility at a weighted average interest rate of 1.8%, and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $750 million. However, based on the ratio of total debt outstanding to EBITDA discussed above, our utilization of the Credit Facility is currently limited to approximately $180 million.

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

We engage in other transactions with a number of the lenders under the Credit Facility. Such lenders or their affiliates may serve as underwriters or initial purchasers of our debt and equity securities, or directly purchase our production, or serve as counterparties to our commodity and interest rate derivative agreements. As of August 6, 2013, all but one of our derivative instrument counterparties are lenders, or their affiliates, under our Credit Facility. Our obligations under our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our Credit Facility. See Item 3, ‘‘Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk’’ below for additional details concerning our derivative instruments.


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Historical Cash Flow
 
Net cash provided by operating activities, net cash provided (used) by investing activities, and net cash (used) provided by financing activities for the six months ended June 30, 2013 and 2012 were as follows:

 
Six Months Ended
 
June 30,
 
2013
 
2012
 
(In Thousands)
Net cash provided by operating activities
$
110,412

 
$
176,424

Net cash provided (used) by investing activities
132,763

 
(399,589
)
Net cash (used) provided by financing activities
(243,810
)
 
220,833

 
Net cash provided by operating activities is primarily affected by sales volumes and commodity prices, net of the effects of settlements of our derivative instruments and changes in working capital. The decrease in net cash provided by operating activities in the six months ended June 30, 2013 compared to the six months ended June 30, 2012, was primarily due to decreased revenues, which was caused by lower sales volumes primarily attributable to divestitures of oil and natural gas properties in South Louisiana and South Texas, which occurred in November 2012 and February 2013, respectively. The decrease in net cash provided by operating activities was also due to lower realized gains on derivative instruments in 2013 as compared to 2012, partially offset by lower production expense in 2013 as compared to 2012.

The components of net cash provided (used) by investing activities for the six months ended June 30, 2013 and 2012 were as follows:
 
 
Six Months Ended
 
June 30,
 
2013
 
2012
 
(In Thousands)
Exploration, development, and leasehold acquisition costs(1)
$
(205,099
)
 
$
(395,781
)
Proceeds from sale of assets
338,977

 
1,102

Other fixed asset costs
(1,115
)
 
(4,910
)
Net cash provided (used) by investing activities
$
132,763

 
$
(399,589
)
____________________________________________
(1)
Cash paid for exploration, development, and leasehold acquisition costs as reflected in the Condensed Consolidated Statements of Cash Flows differs from the reported capital expenditures in the “Capital Expenditures” table below due to the timing of when the capital expenditures are incurred and when the actual cash payments are made, as well as non-cash capital expenditures such as capitalized stock-based compensation costs and the value of common stock issued for the acquisition of oil and natural gas properties.
 
Net cash provided (used) by investing activities is primarily comprised of expenditures for the acquisition, exploration, and development of oil and natural gas properties, net of proceeds from the dispositions of oil and natural gas properties and other capital assets. The increase in net cash provided by investing activities in the six months ended June 30, 2013 compared to the corresponding period of 2012 was primarily due to an increase in proceeds from the sale of assets, due to the South Texas disposition in February 2013, as well as a decrease in exploration, development, and leasehold acquisition cost expenditures during the six months ended June 30, 2013.
 
Net cash used by financing activities increased by $465 million to $244 million in net cash used by financing activities in the six months ended June 30, 2013 from $221 million in net cash provided by financing activities in the six months ended June 30, 2012. This increase in net cash used by financing activities was primarily due to the redemption of the 8½% senior notes due 2014 for $321 million in March 2013. This use of cash by financing activities was partially offset by net proceeds from bank borrowings of $65 million during the six months ended June 30, 2013. Net cash provided by financing activities in the six months ended June 30, 2012 primarily consisted of net proceeds from bank borrowings of $243 million.



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Capital Expenditures
 
Expenditures for property exploration, development, and acquisitions were as follows:
 
 
Six Months Ended
 
June 30,
 
2013
 
2012
 
(In Thousands)
Exploration, development, and acquisition costs:
 

 
 
Direct costs:
 

 
 
Exploration and development
$
178,974

 
$
365,585

Leasehold acquisitions
4,066

 
53,792

Overhead capitalized
20,396

 
20,316

Interest capitalized
1,114

 
4,097

Total capital expenditures(1) 
$
204,550

 
$
443,790

____________________________________________
(1)
Total capital expenditures include cash expenditures, accrued expenditures, and non-cash capital expenditures including the value of common stock issued for oil and natural gas property acquisitions and stock-based compensation capitalized under the full cost method of accounting. Total capital expenditures also include changes in estimated discounted asset retirement obligations of $.6 million and $3 million recorded during the six months ended June 30, 2013 and 2012, respectively.

We have established an exploration and development capital budget of $355 million to $375 million for 2013 that continues our focus on higher-margin oil opportunities. As the benefit of the drilling carry associated with the Eagle Ford Shale development agreement is realized into 2014, our expected capital expenditures are forecasted to be at lower levels than would otherwise be the case absent the drilling carry. Primary factors impacting the level of our capital expenditures include oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions.

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

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

•
estimates of our oil and natural gas reserves;

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

•
our future financial condition and results of operations;

•
our future revenues, cash flows, and expenses;

•
our access to capital and our anticipated liquidity;

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


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•
our outlook on oil and natural gas prices;

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

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

•
potential future asset dispositions and other transactions;

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

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

We believe the expectations, estimates, projections, beliefs, forecasts, and assumptions reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil and natural gas. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included or incorporated in Part I of our 2012 Annual Report on Form 10-K.
 
Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
 
We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information to reflect events or circumstances after the filing of this report with the SEC, except as required by law. All forward-looking statements, expressed or implied, included in this Form
10-Q and attributable to Forest are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or persons acting on our behalf may issue. 



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Table of Contents

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

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2012
 
2013
 
2012
 
(In Thousands)
Net earnings (loss)
$
33,439

 
$
(511,173
)
 
$
(34,509
)
 
$
(543,846
)
Income tax (benefit) expense
(212
)
 
167,074

 
125

 
167,989

Unrealized (gains) losses on derivative instruments, net
(22,913
)
 
(111
)
 
15,398

 
(5,423
)
Interest expense
29,392

 
34,317

 
65,520

 
67,709

Loss on debt extinguishment
—

 
—

 
25,223

 
—

Accretion of asset retirement obligations
549

 
1,597

 
1,793

 
3,195

Ceiling test write-down of oil and natural gas properties
—

 
348,976

 
—

 
383,793

Depreciation, depletion, and amortization
43,804

 
72,987

 
92,347

 
139,957

Stock-based compensation
2,832

 
6,240

 
6,479

 
9,257

Legal proceeding/severance costs
—

 
1,851

 
5,821

 
24,698

Rig stacking
1,258

 
—

 
4,296

 
—

Adjusted EBITDA
$
88,149

 
$
121,758

 
$
182,493

 
$
247,329




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Table of Contents

Item 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We are exposed to market risk, including the effects of adverse changes in commodity prices, interest rates, and foreign currency exchange rates as discussed below.
 
Commodity Price Risk
 
We produce and sell natural gas, oil, and NGLs in the United States. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. In order to reduce the impact of fluctuations in commodity prices, we make use of a commodity hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other derivative instruments with counterparties who, in general, are lenders, or affiliates of such lenders, under our Credit Facility. These instruments, which are typically based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.
 
Swaps
 
In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher than the fixed price, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of June 30, 2013, we had entered into the following swaps:
 
Commodity Swaps
 
 
Natural Gas (NYMEX HH)
 
Oil (NYMEX WTI)
Remaining Swap Term
 
Bbtu
per Day
 
Weighted
Average
Hedged Price
per MMBtu
 
Fair Value
(In Thousands)
 
Barrels
per Day
 
Weighted
Average
Hedged Price
per Bbl
 
Fair Value
(In Thousands)
July 2013 - October 2013
 
145

 
$
3.99

 
$
6,912

 
4,000

 
$
95.53

 
$
(136
)
November 2013 - December 2013
 
160

 
3.98

 
2,416

 
4,000

 
95.53

 
425

Calendar 2014
 
80

 
4.34

 
12,535

 
—

 
—

 
—



Commodity Options
 
In connection with several natural gas and oil swaps entered into, we granted swaptions to the swap counterparties in exchange for our receiving premium hedged prices on the natural gas and oil swaps. These swaptions grant the swap counterparties the option to enter into future swaps with us and may not be exercised until their expiration dates. The table below sets forth the outstanding swaptions as of June 30, 2013.

Commodity Options
 
 
 
 
Natural Gas (NYMEX HH)
 
Oil (NYMEX WTI)
Underlying Term
 
Option Expiration
 
Underlying
Bbtu
Per Day
 
Underlying
Hedged
Price
per MMBtu
 
Fair Value
(In
Thousands)
 
Underlying
Barrels
Per Day
 
Underlying
 Hedged
Price per
Bbl
 
Fair Value
(In
Thousands)
Gas Swaptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Calendar 2014
 
December 2013
 
30

 
$
4.50

 
$
(941
)
 
—

 
$
—

 
$
—

Calendar 2014
 
December 2013
 
10

 
4.51

 
(308
)
 
—

 
—

 
—

Oil Swaptions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Calendar 2014
 
December 2013
 
—

 
—

 
—

 
4,000

 
100.00

 
(1,897
)
Calendar 2014
 
December 2013
 
—

 
—

 
—

 
1,000

 
109.00

 
(120
)
Calendar 2015
 
December 2014
 
—

 
—

 
—

 
3,000

 
100.00

 
(2,310
)
 
The estimated fair value at June 30, 2013 of all our commodity derivative instruments based on various valuation inputs, including published forward prices, was a net asset of approximately $17 million.


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Table of Contents

Derivative Instruments Entered Into Subsequent to June 30, 2013

Subsequent to June 30, 2013, through August 6, 2013, we entered into the following derivative agreements:
Commodity Swaps
 
 
Oil (NYMEX WTI)
Swap Term
 
Barrels Per Day
 
Weighted Average
Hedged Price
per Bbl
July 2013 - December 2013
 
2,000

 
$
99.70

Calendar 2014
 
3,000

 
95.10


In addition to the swaps shown in the table above, we entered into 15 Bbtu per day of purchased natural gas swaps for the period September 2013 - December 2013 that directly offset 15 Bbtu per day of sold natural gas swaps. Additionally, we unwound the last two months of a Calendar 2013 natural gas swap covering 20 Bbtu per day at a hedged price of $4.03 per MMBtu. This brings our natural gas swap position for the period July 2013 - December 2013 to 133.4 Bbtu per day at a weighted average hedged price of $4.01 per MMBtu.

Commodity Options
 
 
 
 
Oil (NYMEX WTI)
Underlying Term
 
Option Expiration
 
Underlying
Barrels Per Day
 
Underlying
Hedged Price per
Bbl
Oil Swaptions:
 
 
 
 
 
 
Calendar 2015(1)
 
December 2014
 
1,000

 
$
106.00

Calendar 2015(1)
 
December 2014
 
1,000

 
99.75

Calendar 2015(1)
 
December 2014
 
1,000

 
99.00

Oil Put Options:
 
 
 
 
 
 
Monthly Calendar 2014
 
Monthly Calendar 2014
 
2,000

 
70.00

____________________________________
(1)
In connection with entering into these oil swaptions, we terminated three of our existing oil swaptions with the counterparties for Calendar 2014. Two of the terminated swaptions covered 2,000 barrels per day with a hedged price per barrel of $100.00, and the third terminated swaption covered 1,000 barrels per day with a hedged price per barrel of $109.00.

Interest Rate Risk
 
The following table presents principal amounts and related interest rates by year of maturity for our Credit Facility and senior notes at June 30, 2013.
 
 
2016
 
2019
 
2020
 
Total
 
 
Credit facility:
 
 
 
 
 
 
 
Borrowings outstanding (in thousands)
$
130,000

 
$
—

 
$
—

 
$
130,000

Interest rate(1)
1.75
%
 
—

 
—

 
1.75
%
Senior notes:
 
 
 

 
 
 
 

Principal outstanding (in thousands)
$
—

 
$
1,000,000

 
$
500,000

 
$
1,500,000

Fixed interest rate
—

 
7.25
%
 
7.50
%
 
7.33
%
Effective interest rate(2)
—

 
7.24
%
 
7.50
%
 
7.33
%
____________________________________________
(1)
Weighted average variable interest rate as of June 30, 2013.
(2)
The effective interest rate on the 7.25% senior notes due 2019 differs from the fixed interest rate due to the amortization of the related premium on the notes.

In June 2013, we voluntarily terminated our fixed-to-floating interest rate swaps under which we had swapped $500 million in notional amount at an 8.5% fixed rate for an equal notional amount at a weighted-average interest rate equal to the 1-month LIBOR plus approximately 5.9%. As part of this termination, we received proceeds of $11 million.


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Table of Contents


Derivative Fair Value Reconciliation
 
The table below sets forth the changes that occurred in the fair values of our derivative instruments during the six months ended June 30, 2013, beginning with the fair value of our derivative instruments on December 31, 2012. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Due to the volatility of oil and natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period. Actual gains and losses recognized related to our commodity derivative instruments will likely differ from those estimated at June 30, 2013 and will depend exclusively on the price of the commodities on the settlement dates specified by the derivative instruments.
 
 
Fair Value of Derivative Contracts
 
Commodity
 
Interest Rate
 
Total
 
(In Thousands)
As of December 31, 2012
$
18,914

 
$
13,060

 
$
31,974

Net increase (decrease) in fair value
6,205

 
(175
)
 
6,030

Net contract gains realized
(8,543
)
 
(12,885
)
 
(21,428
)
As of June 30, 2013
$
16,576

 
$
—

 
$
16,576


Foreign Currency Exchange Risk

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

Item 4.  CONTROLS AND PROCEDURES
 
Evaluation of Disclosure Controls and Procedures
 
We have established disclosure controls and procedures to ensure that material information relating to Forest and its consolidated subsidiaries is made known to the officers who certify Forest’s financial reports and the Board of Directors.
 
Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Michael N. Kennedy, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the quarterly period ended June 30, 2013 (the “Evaluation Date”). Based on this evaluation, they believe that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms; and (ii) is accumulated and communicated to Forest’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
 
Changes in Internal Control over Financial Reporting
 
There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended June 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



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PART II—OTHER INFORMATION
 

Item 1.  LEGAL PROCEEDINGS

On May 25, 2012, a lawsuit, styled Augenbaum v. Lone Pine Resources Inc. et al., was brought 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 complaint alleges 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, 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 alleges 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 asserts 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 alleges 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. The complaint does not specify the amount of such damages. Lone Pine has existing obligations to indemnify Forest, the Individual Defendants, and the Underwriter Defendants in connection with the lawsuit. Forest believes that these claims are without merit and intends to defend the claim against it vigorously.

Except as described above with respect to the Augenbaum complaint being amended to drop the forest fires allegation, there have been no material changes to the disclosure included in Part I, Item 3, of the Annual Report on Form 10-K for the year ended December 31, 2012.

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

Item 1A.  RISK FACTORS

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

Item 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
Unregistered Sales of Equity Securities
 
There were no sales of unregistered equity securities during the period covered by this report.



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Issuer Purchases of Equity Securities
 
The table below sets forth information regarding repurchases of our common stock during the second quarter of 2013. The shares repurchased represent shares of our common stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Forest does not consider this a share buyback program.
 
Period
 
Total # of Shares
Purchased
 
Average Price
Paid Per Share
 
Total # of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
 
Maximum # (or
Approximate Dollar
Value) of Shares that
May Yet be Purchased
Under the Plans or
Programs
April 2013
 
98

 
$
4.74

 
—

 
—

May 2013
 
156,341

 
5.31

 
—

 
—

June 2013
 
311

 
4.37

 
—

 
—

Second Quarter Total
 
156,750

 
$
5.31

 
—

 
—



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Table of Contents

Item 6.  EXHIBITS
(a)

 
Exhibits.
 
 
 
3.1

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

 
 
3.2

 
Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, No. 5, and No. 6, incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-4 for Forest Oil Corporation filed June 4, 2013 (File No. 333-189064).
 
 
 
10.1

 
Amendment No. 5 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 7, 2013.
 
 
 
10.2

 
Forest Oil Corporation 2013 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 17, 2013.
 
 
 
10.3

 
Form of 2013 Restricted Stock Award Agreement - Cliff Vesting, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.4

 
Form of 2013 Restricted Stock Award Agreement - Annual Vesting, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.5

 
Form of 2013 Phantom Stock Unit Award Agreement - Cliff Vesting, incorporated herein by reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.6

 
Form of 2013 Phantom Stock Unit Award Agreement - Annual Vesting, incorporated herein by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.7

 
Form of 2013 Performance Unit Award Agreement - Stock Settled, incorporated herein by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.8

 
Form of 2013 Performance Unit Award Agreement - Cash Settled, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.9

 
Acquisition and Development Agreement, dated April 11, 2013, by and between Forest Oil Corporation, STC Eagleville, LLC, Schlumberger Technology Corporation, Smith International, Inc., and M-I L.L.C., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2013.
 
 
 
10.10

 
Operating Agreement, dated April 11, 2013, by and between Forest Oil Corporation and STC Eagleville LLC, incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 17, 2013.
 
 
 
31.1*

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

 
 
31.2*

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

 
 
32.1+

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

 
 
32.2+

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

 
XBRL Instance Document.
 
 
 
101.SCH++

 
XBRL Schema Document.
 
 
 
101.CAL++

 
XBRL Calculation Linkbase Document.
 
 
 
101.LAB++

 
XBRL Label Linkbase Document.
 
 
 
101.PRE++

 
XBRL Presentation Linkbase Document.
 
 
 
101.DEF++

 
XBRL Definition Linkbase Document.
____________________________________________
*
Filed herewith.
+    Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.


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Table of Contents

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


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Table of Contents

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
FOREST OIL CORPORATION
(Registrant)
 
 
 
August 6, 2013
By:
/s/ PATRICK R. MCDONALD
 
 
Patrick R. McDonald
President and Chief Executive Officer and Director
(on behalf of the Registrant and as
 Principal Executive Officer)
 
 
 
 
By:
/s/ MICHAEL N. KENNEDY
 
 
Michael N. Kennedy
Executive Vice President and
 Chief Financial Officer
 (on behalf of the Registrant and as
 Principal Financial Officer)
 
 
 
 
By:
/s/ VICTOR A. WIND
 
 
Victor A. Wind
Senior Vice President, Chief Accounting Officer, Corporate Controller, and Treasurer
(Principal Accounting Officer)



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Table of Contents

Exhibit Index
3.1

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

 
 
3.2

 
Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, No. 5, and No. 6, incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-4 for Forest Oil Corporation filed June 4, 2013 (File No. 333-189064).
 
 
 
10.1

 
Amendment No. 5 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 7, 2013.
 
 
 
10.2

 
Forest Oil Corporation 2013 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 17, 2013.
 
 
 
10.3

 
Form of 2013 Restricted Stock Award Agreement - Cliff Vesting, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.4

 
Form of 2013 Restricted Stock Award Agreement - Annual Vesting, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.5

 
Form of 2013 Phantom Stock Unit Award Agreement - Cliff Vesting, incorporated herein by reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.6

 
Form of 2013 Phantom Stock Unit Award Agreement - Annual Vesting, incorporated herein by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.7

 
Form of 2013 Performance Unit Award Agreement - Stock Settled, incorporated herein by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.8

 
Form of 2013 Performance Unit Award Agreement - Cash Settled, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed May 24, 2013.

 
 
 
10.9

 
Acquisition and Development Agreement, dated April 11, 2013, by and between Forest Oil Corporation, STC Eagleville, LLC, Schlumberger Technology Corporation, Smith International, Inc., and M-I L.L.C., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 17, 2013.
 
 
 
10.10

 
Operating Agreement, dated April 11, 2013, by and between Forest Oil Corporation and STC Eagleville LLC, incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 17, 2013.
 
 
 
31.1*

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

 
 
31.2*

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

 
 
32.1+

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

 
 
32.2+

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

 
XBRL Instance Document.
 
 
 
101.SCH++

 
XBRL Schema Document.
 
 
 
101.CAL++

 
XBRL Calculation Linkbase Document.
 
 
 
101.LAB++

 
XBRL Label Linkbase Document.
 
 
 
101.PRE++

 
XBRL Presentation Linkbase Document.
 
 
 
101.DEF++

 
XBRL Definition Linkbase Document.

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


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Table of Contents

++    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.


47