Document/ExhibitDescriptionPagesSize 1: 10-K/A Amendment to Annual Report HTML 1.88M
2: EX-23.1 Consent of Experts or Counsel HTML 31K
3: EX-23.2 Consent of Experts or Counsel HTML 33K
4: EX-31.1 Certification -- §302 - SOA'02 HTML 35K
5: EX-31.2 Certification -- §302 - SOA'02 HTML 35K
6: EX-32.1 Certification -- §906 - SOA'02 HTML 30K
7: EX-32.2 Certification -- §906 - SOA'02 HTML 30K
66: R1 Document and Entity Information HTML 58K
53: R2 Consolidated Balance Sheets HTML 151K
64: R3 Consolidated Balance Sheets (Parenthetical) HTML 43K
69: R4 Consolidated Statements of Operations HTML 129K
88: R5 Consolidated Statements of Comprehensive Income HTML 51K
55: R6 Consolidated Statement of Equity HTML 102K
63: R7 Consolidated Statements of Cash Flows HTML 160K
48: R8 Summary of Significant Accounting Policies HTML 249K
38: R9 Property and Equipment HTML 102K
89: R10 Debt HTML 122K
71: R11 Income Taxes HTML 143K
70: R12 Shareholders' Equity HTML 51K
76: R13 Stock-Based Compensation HTML 310K
77: R14 Employee Benefits HTML 302K
74: R15 Fair Value Measurements HTML 100K
78: R16 Derivative Instruments HTML 170K
65: R17 Commitments and Contingencies HTML 61K
67: R18 Costs, Expenses, and Other HTML 56K
73: R19 Selected Quarterly Financial Data (Unaudited) HTML 74K
97: R20 Discontinued Operations HTML 45K
84: R21 Supplemental Financial Data-Oil and Gas Producing HTML 520K
Activities (Unaudited)
59: R22 Summary of Significant Accounting Policies HTML 124K
(Policies)
72: R23 Summary of Significant Accounting Policies HTML 208K
(Tables)
61: R24 Property and Equipment (Tables) HTML 85K
29: R25 Debt (Tables) HTML 93K
85: R26 Income Taxes (Tables) HTML 144K
92: R27 Shareholders' Equity (Tables) HTML 36K
43: R28 Stock-Based Compensation (Tables) HTML 300K
42: R29 Employee Benefits (Tables) HTML 308K
46: R30 Fair Value Measurements (Tables) HTML 101K
47: R31 Derivative Instruments (Tables) HTML 164K
49: R32 Commitments and Contingencies (Tables) HTML 57K
22: R33 Costs, Expenses, and Other (Tables) HTML 45K
82: R34 Selected Quarterly Financial Data (Unaudited) HTML 72K
(Tables)
57: R35 Discontinued Operations (Tables) HTML 42K
60: R36 Supplemental Financial Data-Oil and Gas Producing HTML 527K
Activities (Tables)
33: R37 Summary of Significant Accounting Policies HTML 53K
(Description of the Business, Subsequent Event –
Going Concern and Management’s Plan, Cash
Equivalents, Debt Issue Costs and Inventory)
(Details)
96: R38 Summary of Significant Accounting Policies HTML 58K
(Property and Equipment and Goodwill) (Details)
14: R39 Summary of Significant Accounting Policies (Asset HTML 49K
Retirement Obligations) (Details)
50: R40 Summary of Significant Accounting Policies (Oil, HTML 45K
Natural Gas, and NGL Sales) (Details)
87: R41 Summary of Significant Accounting Policies HTML 43K
(Accounts Receivable) (Details)
31: R42 Summary of Significant Accounting Policies HTML 81K
(Earnings (Loss) per Share) (Details)
41: R43 Summary of Significant Accounting Policies HTML 163K
(Comprehensive Income (Loss)) (Details)
45: R44 Property and Equipment (Details) HTML 69K
54: R45 Property and Equipment (Divestitures) (Narrative) HTML 132K
(Details)
21: R46 Debt (Details) HTML 293K
37: R47 Income Taxes (Components of Income Tax Expense HTML 60K
(Benefit)) (Details)
16: R48 Income Taxes (Income Before Income Tax, Domestic HTML 41K
and Foreign) (Details)
86: R49 Income Taxes (Reconciliation of Income Tax HTML 57K
Computed by Applying Statutory Federal Income Tax
Rate) (Details)
30: R50 Income Taxes (Schedule of Deferred Tax Assets and HTML 86K
Liabilities) (Details)
83: R51 Income Taxes (Summary of Income Tax Contingencies) HTML 36K
(Details)
34: R52 Income Taxes (Summary of Income Taxes Receivable) HTML 30K
(Details)
51: R53 Shareholders' Equity (Common Stock and Preferred HTML 63K
Stock) (Details)
15: R54 Shareholders' Equity (Lone Pine Initial Public HTML 66K
Offering and Spin-off) (Details)
19: R55 Stock-Based Compensation (Narrative) (Details) HTML 89K
44: R56 Stock-Based Compensation (Details) HTML 197K
25: R57 Stock-Based Compensation (Range of Exercise HTML 50K
Prices) (Details)
90: R58 Stock-Based Compensation (Employee Stock Purchase HTML 68K
Plan) (Details)
56: R59 Employee Benefits (Expected Benefit Payments) HTML 84K
(Details)
75: R60 Employee Benefits (Fair Value of Plan Assets) HTML 88K
(Details)
36: R61 Employee Benefits (Fair Value of Plan Assets HTML 81K
Parenthetical) (Details)
39: R62 Employee Benefits (Investments of the Plan and HTML 80K
Funded Status) (Details)
81: R63 Employee Benefits (Annual Periodic Expense and HTML 75K
Actuarial Assumptions) (Details)
79: R64 Employee Benefits (Other Employee Benefit Plans) HTML 45K
(Details)
58: R65 Fair Value Measurements (Details) HTML 42K
80: R66 Fair Value Measurements (Details 2) HTML 66K
35: R67 Derivative Instruments (Details) HTML 46K
62: R68 Derivative Instruments (Details 2) HTML 51K
91: R69 Derivative Instruments (Details 3) HTML 42K
18: R70 Derivative Instruments (Details 4) HTML 74K
28: R71 Commitments and Contingencies (Details) HTML 83K
52: R72 Commitments and Contingencies (Narrative) HTML 44K
(Details)
24: R73 Costs, Expenses, and Other (Details) HTML 79K
94: R74 Selected Quarterly Financial Data (Unaudited) HTML 55K
(Details)
32: R75 Discontinued Operations (Details) HTML 63K
26: R76 Supplemental Financial Data-Oil and Gas Producing HTML 134K
Activities (Schedule of Proved Developed and
Undeveloped Oil and Gas Reserve) (Details)
27: R77 Supplemental Financial Data-Oil and Gas Producing HTML 42K
Activities (Capitalized Costs Relating to Oil and
Gas Producing Activities) (Details)
20: R78 Supplemental Financial Data-Oil and Gas Producing HTML 52K
Activities (Cost Incurred in Oil and Gas Property
Acquisition, Exploration, and Development
Activities) (Details)
23: R79 Supplemental Financial Data-Oil and Gas Producing HTML 62K
Activities (Results of Operations for Oil and Gas
Producing Activities) (Details)
68: R80 Supplemental Financial Data-Oil and Gas Producing HTML 115K
Activities (Standardized Measure of Discounted
Future Cash Flows Relating to Proved Reserves)
(Details)
93: XML IDEA XML File -- Filing Summary XML 156K
17: EXCEL IDEA Workbook of Financial Reports XLSX 545K
40: EXCEL IDEA Workbook of Financial Reports (.xls) XLS 4.83M
8: EX-101.INS XBRL Instance -- fst-20131231 XML 7.14M
10: EX-101.CAL XBRL Calculations -- fst-20131231_cal XML 446K
11: EX-101.DEF XBRL Definitions -- fst-20131231_def XML 1.30M
12: EX-101.LAB XBRL Labels -- fst-20131231_lab XML 3.42M
13: EX-101.PRE XBRL Presentations -- fst-20131231_pre XML 1.78M
9: EX-101.SCH XBRL Schema -- fst-20131231 XSD 316K
95: ZIP XBRL Zipped Folder -- 0000038079-14-000080-xbrl Zip 550K
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No x
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). Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the
registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,”“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
Accelerated filer x
Non-accelerated filer o
(Do
not check if a smaller
reporting company)
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 28, 2013, the last business day of the
registrant’s most recently completed second fiscal quarter, was $483,491,861 (based on the closing price of such stock).
There were 119,076,708 shares of the registrant’s common stock, par value $.10 per share, outstanding as of February 19, 2014.
As previously disclosed in Item 8.01 of our Current Report on Form 8-K filed on August 11, 2014 (the “Form 8-K”), Forest’s management determined that certain material weaknesses existed in our internal control over financial reporting at year end 2013. Our independent registered public accounting firm, Ernst & Young LLP (“EY”) has reached the same conclusion. Accordingly, we disclosed that our
internal control over financial reporting was ineffective at December 31, 2013, and that both management’s assessment of, and EY’s report on, internal control over financial reporting as of December 31, 2013, included in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed on February 26, 2014 (the “Original Filing”), should no longer be relied upon. We also disclosed management’s determination that Forest’s disclosure controls and procedures were not effective at a reasonable level as of December 31, 2013 and March 31, 2014. Finally, we disclosed that EY and Forest would perform additional testing of Forest’s (i) internal control over financial
reporting for the year ended December 31, 2013, and (ii) financial statements for each of the three years included in the Original Filing.
The additional testing of Forest’s internal control over financial reporting, and the financial statements, has now been completed. We note that the additional testing did not result in a restatement of the financial statements included in the Original Filing. We are filing this Amendment No. 1 (this “Form 10-K/A”) to the Original Filing to address (i) the material weaknesses in our internal control over financial reporting that have been identified since the date of the Original Filing, and (ii) an audit opinion included in this Form 10-K/A by EY that has been amended, relative to the audit opinion included in the Original Filing, to include
disclosure regarding EY’s opinion of our ability to continue to operate as a going concern. EY has included the “going concern” disclosure in its audit opinion due to the fact that we have determined that by year end 2014 the ratio of our total debt to EBITDA may exceed the maximum allowed under our bank credit facility, unless we undertake certain mitigating actions such as obtaining a waiver or amendment to the bank credit facility, selling oil and gas properties or, in the alternative, obtaining a new credit facility or other alternative financing. Absent such actions, a resultant breach of the financial covenant could cause a default under the bank credit facility, potentially resulting in an acceleration of all amounts outstanding under the facility as well as our senior unsecured notes due 2019 and 2020. As of September 30, 2014, we had approximately $13 million
outstanding under the credit facility and $800 million outstanding principal amount of notes. The immediate acceleration of debt maturities of this magnitude would likely result in our need to propose a plan of reorganization with creditors, seek relief from the acceleration of said debt maturities, or find some other means of resolving the breach. Rather than focusing financial resources on mitigating this issue solely for the purpose of avoiding the “going concern” audit opinion and disclosure, Forest has chosen to concentrate resources on completing the previously announced combination transaction with Sabine Oil & Gas LLC. If the transaction is completed, Forest’s bank credit facility will be terminated before any potential breach of the financial covenant in the credit facility.
This
Form 10-K/A sets forth the Original Filing in its entirety; however, pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), this Form 10-K/A amends and restates only the following Items of the Original Filing, and only with respect to matters relating to the material weaknesses in internal control over financial reporting and the going concern disclosure in the audit opinion:
Part I
•
Item 1A. Risk Factors
Part II
•
Item
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
•
Item 8. Financial Statements and Supplementary Data
•
Item 9A. Controls and Procedures
Part IV
•
Item 15. Exhibits, Financial Statement Schedules
With
respect to Item 15, we are including for filing with this Form 10-K/A only (i) certifications from our Chief Executive Officer and Chief Financial Officer as Exhibits 31.1, 31.2, 32.1, and 32.2, (ii) an updated consent from EY as Exhibit 23.1, (iii) an updated consent from DeGolyer and MacNaughton as Exhibit 23.2, and (iv) various exhibits related to XBRL. In addition, we are enhancing the disclosure in Item 7 in order to comply with comments
i
received from the staff of the Securities and Exchange Commission on the Original
Filing. As noted above, the additional testing on the financial statements and on our internal control over financial reporting did not result in a restatement of the financial statements included in the Original Filing.
Except as otherwise set forth in this Explanatory Note, this Form 10-K/A does not modify or update other disclosures presented in the Original Filing. Accordingly, except for the items identified above, this Form 10-K/A speaks as of February 26, 2014, the date of the Original Filing, and any forward-looking statements represent management’s views as of the date of the Original Filing and should not be assumed to be correct as of any date thereafter. This Form 10-K/A should be read in conjunction with our other filings made with the Securities and Exchange Commission subsequent to the date
of the Original Filing.
i
PART I
Item 1. Business.
General
Throughout this Annual Report on Form 10-K, we use the terms “Forest,”“Company,”“we,”“our,” and “us” to refer to Forest Oil Corporation and its subsidiaries.
In the following discussion, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). See “Forward-Looking Statements,” below, for more details. We also use a number of terms used in the oil and gas industry. See “Glossary of Oil and Gas Terms” for the definition of certain terms.
Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (sometimes referred to as “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’s
total estimated proved oil and gas reserves as of December 31, 2013 were approximately 625 Bcfe, all of which are located in the United States.
Strategy
Forest’s long-term operating strategy seeks to build shareholder value by pursuing the development of oil and natural gas assets within our operational areas located in Eagle Ford in South Texas; Ark-La-Tex in East Texas, Louisiana, and Arkansas; and Permian Basin in West Texas. We strive to maintain a large number of commodity-diverse drilling locations that provide us with the flexibility to allocate capital to projects that generate the highest margins depending on the current commodity price
environment, which currently include oil or natural gas liquids drilling projects. We devoted the majority of our capital expenditures to oil and natural gas liquids projects in 2013 and we plan to continue to do so in 2014. Our asset base and development efforts are focused in areas where we have concentrated land positions, a large drilling inventory, and operational control. Our growth strategy may also be supplemented from time to time through opportunistic acquisitions that complement our existing asset base to increase the size and scale of our development and resource opportunities. We may also sell properties when the opportunity arises or business conditions warrant, as demonstrated by the sale of our natural gas assets in South Texas and our Texas Panhandle properties in 2013.
Core Operational Areas
Our
core operational areas consist of drilling projects that have exposure to oil, natural gas, and natural gas liquids. Our primary areas of focus in 2014 will be in Eagle Ford in South Texas and Ark-La-Tex in East Texas.
Eagle Ford
Our Eagle Ford assets are located in Gonzales County in South Texas. During 2013, we continued progress toward holding an aggregate of 49,000 gross (24,500 net) acres in the area and we currently anticipate that this will be accomplished during the first half of 2014. In April 2013, we announced a joint development agreement with an industry partner that allowed us to increase our pace of drilling activity during 2013 and implement technological refinements and enhancements. These enhancements involve ongoing micro-seismic and subsurface data analysis and reservoir
studies that are being used to optimize well placement, lateral length, and fracture stimulation techniques and design. We are attempting to operate more efficiently through a combination of decreased drilling and completion time, the utilization of a more targeted completion design, and capitalizing on operational synergies associated with pad drilling. Drilling and completion costs for 2013 averaged $6 million per gross well as compared to $7 million for the wells drilled in 2012. In addition, we have entered into a gathering, treating, and processing agreement that will provide central facility gathering, transportation, gas processing, and water handling for our Eagle Ford production. This will help streamline our operations and provide cost savings for this oil asset. The facility is expected to be fully operational by the fourth quarter of 2014. We expect to see improvement in well costs
1
following the completion of centralized production facilities, the use of existing pad locations, and continued optimization of completion techniques. In 2014, we plan to operate a two-rig drilling program in Eagle Ford.
Ark-La-Tex
We currently hold an acreage position of 234,000 gross (162,000 net) acres in the greater Ark-La-Tex. Approximately 78% of the acreage is held by production, of which 85% is operated by Forest. We believe that this asset base provides repeatable and predictable drilling and recompletion opportunities within multiple stacked-pay intervals, including the Cotton Valley, Haynesville, and other formations. Recent drilling activity has focused on the liquids-rich Cotton Valley and other
formations in East Texas. During 2012, we changed our focus to target primarily liquids-rich drilling projects to take advantage of these higher-margin opportunities as a result of a decrease in natural gas prices. In 2013, we continued to primarily target the Cotton Valley formation and experienced relatively consistent and predictable results. We drilled a total of six wells in 2013 that had a 30-day average gross production rate of 8.7 MMcfe/d (40% liquids). In 2014, we plan to continue targeting the Cotton Valley and our efforts will focus on transitioning to multi-well pad drilling in certain areas to improve efficiency as we seek to reduce well costs. We plan to operate a three-rig drilling program in Ark-La-Tex during 2014.
Acquisition and Divestiture Activities
We currently have
no plans for acquisitions. However, in the future we may pursue acquisitions that meet our criteria for investment returns. We also may divest non-core assets from time to time to, among other things, upgrade our portfolio, increase our operational efficiencies, and improve our financial position. As described below, we have focused on divestitures in recent years in order to reduce our indebtedness.
In October 2013, we entered into an agreement to sell all of our oil and natural gas properties located in the Texas Panhandle for $1 billion in cash. The purchase price was adjusted at closing on November 25, 2013 to $944 million in order to, among other things, reflect an economic effective date of October
1, 2013. In addition to the net cash proceeds of $944 million received at closing, $44 million was closed into escrow, which Forest may receive as consents-to-assign are received and post-closing title curative work is completed. Moreover, there is an additional $10 million in escrow that supports post-closing indemnities that we may owe to the buyer under the terms of the purchase and sale agreement. Any of the $10 million remaining in escrow at the one-year anniversary of the closing will be paid to us. As of February 19, 2014, we have received $21 million of the $44 million closed into escrow. We estimated the proved reserves associated with these properties were 517 Bcfe at the time of
sale.
In August 2013, we entered into an agreement to sell a portion of our largely undeveloped acreage position located in Crockett County in the Permian Basin of West Texas. This transaction closed on September 10, 2013 and we received net cash proceeds of $31 million.
In January 2013, we entered into an agreement to sell all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford oil properties. This transaction closed on February 15, 2013 and we received net cash proceeds of $321 million. We estimated the proved reserves
associated with these properties were 223 Bcfe at the time of sale.
In November 2012, we sold all of our oil and natural gas properties located in South Louisiana for net cash proceeds of $211 million. We estimated the proved reserves associated with these properties were 39 Bcfe at the time of sale. In October 2012, we sold the majority of our East Texas natural gas gathering assets for net cash proceeds of $29 million.
In June 2011, we completed an initial public offering of approximately 18% of the common stock of our then wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which held our ownership interests in our Canadian operations. On September 30,
2011, we distributed, or spun-off, our remaining 82% ownership in Lone Pine to our shareholders, by means of a special stock dividend of Lone Pine common shares. We estimated the proved reserves associated with these properties were 510 Bcfe at the time of spin-off.
2
In 2009, we sold oil and natural gas properties located in the Permian Basin in West Texas and New Mexico in three separate transactions for net proceeds of $908 million in cash. We estimated the proved reserves associated with these properties were 541 Bcfe at the time of sale.
Reserves
The
following table summarizes our estimated quantities of proved reserves as of December 31, 2013, all of which are located in the United States, based on the NYMEX Henry Hub (“HH”) price of $3.67 per MMBtu for natural gas and the NYMEX West Texas Intermediate (“WTI”) price of $97.33 per barrel for oil, each of which represents the unweighted arithmetic average of the first-day-of-the-month prices during the twelve-month period prior to December 31, 2013. See “Preparation of Reserves Estimates” below and Note 14 to the Consolidated Financial Statements for additional information regarding our estimated proved reserves.
Estimated
Proved Reserves
Natural Gas
(MMcf)
Oil (MBbls)
Natural Gas Liquids (MBbls)
Total
(MMcfe)(1)
Developed
336,342
6,151
6,855
414,378
Undeveloped
118,249
10,523
4,856
210,523
Total
estimated proved reserves
454,591
16,674
11,711
624,901
____________________________________________
(1)
Oil
and natural gas liquids are converted to gas-equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. This conversion is based on energy equivalence and not price equivalence. For 2013, the average of the first-day-of-the-month natural gas price was $3.67 per Mcf, and the average of the first-day-of-the-month oil price was $97.33 per barrel. If a price-equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 27 Mcf per barrel of oil and approximately 10 Mcf per barrel of NGLs (based on the average of the first-day-of-the-month Mt. Belvieu pricing for NGLs in 2013).
As
of December 31, 2013, we had estimated proved reserves of 625 Bcfe, a decrease of 54% compared to 1,363 Bcfe of estimated proved reserves at December 31, 2012. During 2013, we added 148 Bcfe of estimated proved reserves through extensions and discoveries primarily driven by our 2013 drilling activity in the Eagle Ford in South Texas and Cotton Valley in East Texas. These reserve additions were offset by property sales of 800 Bcfe
and net negative revisions of 10 Bcfe. The net negative revisions of 10 Bcfe were comprised of (i) the reclassification of 41 Bcfe of proved undeveloped reserves (“PUDs”) to probable undeveloped reserves for PUDs that are not expected to be developed five years from the time the reserves were initially disclosed, (ii) negative performance revisions of 9 Bcfe, and (iii) positive pricing revisions of 40 Bcfe.
As of December 31, 2013, we had estimated proved undeveloped reserves of 211 Bcfe, or 34% of estimated
proved reserves, compared to 425 Bcfe, or 31% of estimated proved reserves as of December 31, 2012. The net decrease of 215 Bcfe was primarily due to property sales including 286 Bcfe of proved undeveloped reserves. During 2013, we invested $75 million to convert 22 Bcfe of our December 31, 2012 PUDs to proved developed reserves. The rate at which we convert PUDs to proved developed reserves has been negatively impacted in the last several years due to our
transition away from developing natural gas reserves, many of which were reclassified to probable reserves in the last several years, and towards the development of oil reserves. In connection with this transition, we drilled a high percentage of non-proved locations in an effort to hold leases that would otherwise be lost if instead we were to drill proved undeveloped locations that are on leases already held by producing wells. This trend continued throughout 2013, however, we expect to increase our PUD conversion rate in 2014. As of December 31, 2013, we have no PUDs that have remained undeveloped for five years or more after they were initially disclosed as PUDs.
Preparation of Reserves Estimates
Reserves
estimates included in this Annual Report on Form 10-K are prepared by Forest’s internal staff of engineers with significant consultation with internal geologists and geophysicists. The reserves estimates are based on production performance and data acquired remotely or in wells, and are guided by petrophysical, geologic,
3
geophysical, and reservoir engineering models. Access to the database housing reserves information is restricted to select individuals from our engineering department. Moreover, new reserves estimates and significant changes to existing reserves are reviewed and approved by various levels of management, depending on their magnitude. Proved reserves estimates are reviewed and approved by the Senior Vice President,
Corporate Engineering and Technology, and at least 80% of our proved reserves, based on net present value, are audited by independent reserve engineers (see “Independent Audit of Reserves” below) prior to review by the Audit Committee. In connection with its review, the Audit Committee meets privately with personnel from DeGolyer and MacNaughton, the independent petroleum engineering firm that audits our reserves, to confirm that DeGolyer and MacNaughton has not identified any concerns or issues relating to the audit and maintains independence. In addition, Forest’s internal audit department randomly selects a sample of new reserves estimates or changes made to existing reserves and tests to ensure that they were properly documented and approved.
Forest’s Senior Vice President, Corporate Engineering and Technology, who has held this
position since January 2013, has 36 years of experience in oil and gas exploration and production and received a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. Prior to January 2013, he held positions of increasing responsibility at Forest since joining the company in 2001, including most recently Vice President, Corporate Engineering, a position in which he was also primarily responsible for overseeing the preparation of reserves estimates. Prior to joining Forest, he held various positions in reservoir engineering and corporate planning with Phillips Petroleum, Midcon Exploration, and Apache Corporation.
Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective
process of estimating subsurface accumulations of oil, natural gas liquids, and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, oil, natural gas liquids, and natural gas quantities ultimately recovered will vary from reserves estimates. See Part I, Item 1A “Risk Factors” below for a description of some of the risks and uncertainties associated with our business and reserves.
Independent Audit of
Reserves
We engage independent reserve engineers to audit a substantial portion of our reserves. Our audit procedures require the independent engineers to prepare their own estimates of proved reserves for fields comprising at least 80% of the aggregate net present value, discounted at 10% per annum (“NPV”), of our year-end proved reserves. The fields selected for audit also must comprise at least 80% of Forest’s fields based on the NPV of such fields and a minimum of 80% of the NPV added during the year through discoveries, extensions, and acquisitions. The procedures prohibit exclusions of any fields, or any part of a field, that comprise part of the top 80%. The independent reserve engineers compare their own estimates to those prepared by Forest. Our audit guidelines require Forest’s internal estimates, which are used for financial reporting and disclosure purposes,
to be within 5% of the independent reserve engineers’ quantity estimates. The independent reserve audit is conducted based on reserve definition and cost and price parameters specified by the Securities and Exchange Commission (“SEC”).
For the years ended December 31, 2013, 2012, and 2011, we engaged DeGolyer and MacNaughton, an independent petroleum engineering firm, to perform reserve audit services. For the year ended December 31, 2013, DeGolyer and MacNaughton independently audited estimates relating to properties constituting over 87% of our reserves by NPV as of December 31,
2013. When compared on a field-by-field basis, some of Forest’s estimates of proved reserves were greater and some were less than the estimates prepared by DeGolyer and MacNaughton. However, in the aggregate, Forest’s estimates of total proved reserves were within 3% of DeGolyer and MacNaughton’s aggregate estimate of proved reserves quantities for the fields audited. The lead technical person at DeGolyer and MacNaughton primarily responsible for overseeing the audit of our reserves received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University, is a Registered Professional Engineer in the State of Texas, is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists, and has 39 years of experience in oil and gas reservoir studies and reserves evaluations.
4
Drilling Activities
The following table summarizes the number of wells drilled during 2013, 2012, and 2011, all of which are located in the United States, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which we do not have a working interest. As of December 31, 2013, we had 9 gross (5 net) wells in progress, all of which are located in the United States. During 2013,
we drilled a total of 93 gross (45 net) wells, of which 41 were classified as exploratory and 52 were classified as development.
A
well classified as productive does not always provide economic levels of production.
(2)
A non-productive well is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well; also known as a dry well (or dry hole).
Oil and Natural Gas Wells and Acreage
Productive Wells
The following table summarizes our productive wells as of December 31,
2013, all of which are located in the United States. Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. As of December 31, 2013, we owned interests in 40 gross wells containing multiple completions.
Gross
Net
Natural
Gas
1,432
1,001
Oil
93
68
Total
1,525
1,069
5
Acreage
The following table summarizes developed and undeveloped acreage in which we owned a working interest or held an exploration license as of December 31, 2013. A substantial majority of our developed acreage is subject to mortgage liens securing our bank credit facility. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary, as well as acreage related to any options held by us to acquire additional leasehold interests. At December 31, 2013, approximately 36%, 30%,
and 16% of our net undeveloped acreage in the United States was held under leases that will expire in 2014, 2015, and 2016, respectively, if not extended by exploration or production activities.
Developed
Acreage
Undeveloped
Acreage
Location
Gross
Net
Gross
Net
United
States(1)
239,089
159,927
189,999
121,008
South Africa(2)
—
—
1,235,500
657,286
Italy
—
—
107,043
86,507
Total
239,089
159,927
1,532,542
864,801
____________________________________________
(1)
Concentrations
of net acres in the United States as of December 31, 2013 include: 162,000 net acres in Ark-La-Tex in East Texas, Louisiana, and Arkansas; 24,500 net acres in Eagle Ford; and 63,500 net acres in Permian Basin in West Texas.
(2)
In December 2012, we entered into agreements to dispose of our interests in the Block 2A Production Right and the Block 2C Exploration Right in South Africa. The abandonment of the Block 2C Exploration Right was completed in December 2013, with Forest receiving $9 million. The disposal of our interest in the Block 2A Production Right is contingent upon the approval of the government
of South Africa, which has not yet occurred. Upon the completion of this transaction, if it occurs, we will no longer hold any acreage in South Africa.
6
Production, Average Sales Prices, and Production Costs
The following table reflects production, average sales price, and production cost information for the years ended December 31, 2013, 2012, and 2011
for continuing operations. All of our production occurred in the United States for the years presented and we do not have any fields that individually contain 15% or more of our total estimated proved reserves.
Production costs excluding production and property taxes (per Mcfe)
1.17
1.02
.92
Production
and property taxes
.20
.28
.33
Total production costs (per Mcfe)
$
1.37
$
1.30
$
1.25
____________________________________________
(1)
Oil
and natural gas liquids are converted to gas-equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. This conversion is based on energy equivalence and not price equivalence. For 2013, the average of the first-day-of-the-month natural gas price was $3.67 per Mcf, and the average of the first-day-of-the-month oil price was $97.33 per barrel. If a price-equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 27 Mcf per barrel of oil and approximately 10 Mcf per barrel of NGLs (based on the average of the first-day-of-the-month Mt. Belvieu pricing for NGLs in 2013).
Marketing
and Delivery Commitments
Our natural gas production is generally sold on a month-to-month basis in the spot market, priced in reference to published indices. Our oil production is generally sold under short-term contracts at prices based upon refinery postings or NYMEX WTI monthly averages and is typically sold at the wellhead. Our natural gas liquids production is typically sold under term agreements at prices based on postings at large fractionation facilities. We believe that the loss of one or more of our current oil, natural gas, or natural gas liquids purchasers would not have a material adverse effect on our ability to sell our production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption. We had no material delivery
commitments as of February 19, 2014.
Competition
We encounter intense competition in all aspects of our business, including acquisition of properties and oil and natural gas leases, marketing oil and natural gas, obtaining services, and securing drilling rigs and other
7
equipment necessary for drilling and completing wells. In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Our ability
to increase production and reserves in the future will depend on our ability to generate successful prospects on our existing properties, execute on major development drilling programs, and acquire additional leases and prospects for future development and exploration. A large number of the companies that we compete with have greater and more productive assets, substantially larger staffs, and greater financial and operational resources than we have. Many of our competitors not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also may have integrated operations that include refining and processing of oil and natural gas products as well as the distribution and marketing of such products. Because of our relatively small size and capital constraints, we may find it increasingly difficult to effectively compete in our markets.
Industry
Regulation
Our oil and gas operations are subject to various national, state, and local laws and regulations in the jurisdictions in which we operate. These laws and regulations may be changed in response to economic or political conditions. As a result, our regulatory burden may increase in the future. Laws and regulations have the potential of increasing our cost of doing business and, consequently, could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.
Matters subject to current governmental regulation or pending legislative or regulatory changes include the production, handling, storage, transportation, and disposal of oil and natural gas, by-products from oil and natural gas, and other
substances produced or used in connection with oil and natural gas operations. Jurisdictions in which we operate have adopted laws and regulations governing bonding or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning our operations, the spacing of wells, unitization and pooling of properties, taxation, and the use of derivative hedging instruments. Our operations are also subject to permit requirements for the drilling of wells and regulations relating to the location of wells, the method of drilling and the casing of wells, surface use and restoration of properties on which wells are located, and the plugging and abandonment of wells. Failure to comply with the laws and regulations in effect from time to time may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that could delay, limit,
or prohibit certain of our operations. At various times, regulatory agencies have imposed price controls and limitations on oil and natural gas production. In order to conserve supplies of oil and natural gas, these agencies may restrict the rates of flow of oil and natural gas wells below actual production capacity. Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws generally prohibit
the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Certain of our operations are conducted on federal land pursuant to oil and natural gas leases administered by the Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed BLM regulations and orders (which are subject to change by the BLM). In addition to permits required from other agencies, lessees must obtain a permit from the BLM prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production, and the removal of facilities. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially
and adversely affect our financial condition and operations.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) imposes reporting and other requirements on our business and operations, including with respect to payments made to U.S. and foreign governments related to our oil and gas exploration and development activities. The legislation also imposes requirements and oversight on our derivatives transactions, including clearing, margin, and position limits requirements. Significant regulations have been promulgated by the SEC, the Commodity Futures Trading
8
Commission, and other regulatory agencies
to implement these requirements and provide certain exemptions for qualified end-users. This legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. The imposition of these types of requirements or limitations could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activities.
Additional proposals and proceedings that might affect the oil and natural gas industry are regularly considered by Congress, the states, local governments, the Federal Energy Regulatory Commission, and the courts. We cannot predict when or whether any such proposal, or any additional new legislative or regulatory proposal, may become effective. No material portion of Forest’s business is subject to renegotiation of profits or termination of contracts
or subcontracts at the election of the federal government.
Environmental and Climate Change Regulation
We are subject to stringent national, state, and local laws and regulations in the jurisdictions where we operate relating to environmental protection, including the manner in which various substances such as wastes generated in connection with oil and natural gas exploration, production, and transportation operations are managed. Compliance with these laws and regulations can affect the location or size of wells and facilities, prohibit or limit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties when production ceases. Failure to comply with these laws and regulations may result in the assessment of administrative,
civil, or criminal penalties, imposition of remedial obligations, incurrence of additional compliance costs, and even injunctions that limit or prohibit exploration and production activities or that constrain the disposal of substances generated by oil field operations.
We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used for the exploration and production of oil and natural gas. Although we believe we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment, disposal, or release
of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws and regulations imposing joint and several or strict liability without regard to fault or the legality of the original conduct and that could require us to remove previously disposed wastes or remediate property contamination, or to perform well pluggings or pit closures or other actions of a remedial or injunctive nature to prevent future contamination.
Our operations produce wastewater that is disposed via injection in underground wells. These wells are regulated under the Safe Drinking Water Act (the “SDWA”) and similar state and local laws. The underground injection well program under the SDWA requires permits from the United States Environmental Protection Agency (“EPA”) or analogous state agencies for our disposal wells, establishes
minimum standards for injection well operations, and restricts the types and quantities of fluids that may be injected. We believe that our disposal well operations comply with all applicable requirements under the SDWA and similar state and local laws. However, a change in the regulations or the inability to obtain permits for new injection wells in the future may affect the Company’s ability to dispose of produced waters and ultimately increase the cost of the Company’s operations.
Hydraulic fracturing is an important process used in the completion of our oil and natural gas wells. The process involves the injection of water, sand, and chemicals under pressure into low-permeability formations to fracture the surrounding
rock and stimulate production. The process is typically regulated by state oil and gas commissions. Various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, control requirements, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds and in some municipalities. For instance, Texas, Colorado, and Louisiana have adopted far-reaching rules that require the public disclosure of chemicals used in the hydraulic fracturing process, with the Texas rules applicable to fracturing treatments on wells with initial drilling permits issued on or after February 1, 2012, and the Colorado rules applicable to fracturing treatments performed on or after April
1, 2012. The Louisiana regulations require operators to disclose all additives used in
9
hydraulic fracturing fluids and the names and concentrations of chemicals subject to Occupational Safety and Health Administration Hazard Communication requirements that are not deemed a trade secret. The Louisiana requirements are effective for wells with drilling permits issued on or after October 20, 2011. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Several federal entities,
including the EPA, also have asserted potential regulatory authority over hydraulic fracturing, and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with the results of the study anticipated to be available for review in 2014. In addition, Congress has considered legislation that would amend the SDWA to encompass all hydraulic fracturing activities. Such a provision would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and record keeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. If such legislation is adopted in the future, it would establish an additional level of regulation and impose additional costs on our operations. See Part I, Item 1A “Risk Factors—We may incur significant
costs related to environmental and other governmental laws and regulations, including those related to “hydraulic fracturing,” that may materially affect our operations” and “Recently proposed or finalized rules and guidance imposing more stringent requirements on the oil and gas exploration and production industry could cause us to incur increased capital expenditures and operating costs as well as decrease our levels of production” below.
Nearly half of the states in the U.S., either individually or through multi-state initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases (“GHGs”). Also, the Supreme Court held in Massachusetts, et al. v. EPA (2007) that carbon dioxide may be regulated as an “air pollutant”
under the federal Clean Air Act, and subsequently in December 2009, the EPA determined that GHG emissions present an endangerment to public health and the environment because such emissions, according to the EPA, are contributing to warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to implement regulations that would restrict GHG emissions under existing provisions of the Clean Air Act. The scope of the EPA’s authority to regulate GHG emissions, however, is currently being reviewed by the U.S. Supreme Court, with a decision expected in spring or summer of 2014. On November 8, 2010, the EPA finalized GHG reporting requirements for the petroleum and natural gas industries. Under this final rule, owners or operators of facilities that contain petroleum and natural gas systems, as defined by the rule, and emit 25,000 metric tons or more of GHGs per year per basin (expressed as carbon
dioxide equivalents) are to report emissions from all source categories located at the facility for which emission calculation methods are defined in the rule. These rules have increased compliance costs on our operations.
We believe that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with applicable environmental laws and regulations in effect at the present time and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that we will not be adversely affected in the future. We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the United States and other relevant international jurisdictions. We employ an environmental, health, and safety
department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance against the costs of cleanup operations, public liability, and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. In addition, some pollution-related risks may not be insurable.
Employees
As of December 31, 2013, we had 363 employees. As of February 19,
2014, we had 223 employees. None of our employees is currently represented by a union for collective bargaining purposes.
10
Geographical Data
Forest operates in one industry segment, oil and gas exploration and production, and has one reportable geographical business segment, the United States.
Offices
Our corporate office is located in leased
space at 707 17th Street, Denver, Colorado. We maintain an office in Houston, Texas, and also lease or own field offices in the areas in which we conduct operations.
Title to Properties
Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry. Under the terms of our bank credit facility, we have granted the lenders a lien on the substantial majority of our properties. In addition, our properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, and restrictions, and for current taxes not yet due. Forest’s general practice is to conduct a title examination
on material property acquisitions. Prior to the commencement of drilling operations, a title examination and, if necessary, curative work is performed. The methods of title examination that we have adopted are reasonable in the opinion of management and are designed to ensure that production from our properties, if obtained, will be salable by Forest.
Glossary of Oil and Gas Terms
The terms defined in this section are used throughout this Annual Report on Form 10-K. Certain definitions, including the definitions of proved reserves, proved developed reserves, and proved undeveloped reserves, have been abbreviated from the applicable definitions contained in Rule 4-10(a) of Regulation S-X under the Securities Exchange Act of 1934.
Bbl. One
stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.
Bbtu. One billion British Thermal Units.
Btu. A British Thermal Unit, or the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.
Condensate. A
mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface temperature and pressure.
Developed acreage. Acreage that is held by producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole; dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Also referred to as a non-productive well.
Equivalent
volumes. Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.
11
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.
Farmout. An assignment of an interest in a drilling location
and related acreage conditional upon the drilling of a well on that location or the undertaking of other work obligations.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Full cost pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration, and development activities are included. Any costs related to production, general and administrative expense, or similar activities are not included.
Gross
acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
HH or Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the NYMEX.
Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.
Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of
a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.
Liquids. Oil, condensate, and natural gas liquids.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. Thousand barrels of crude oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.
Mcf. Thousand
cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.
MMBtu. One million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.
NGL
or natural gas liquids. Liquid hydrocarbons found in natural gas which may be extracted as separate components, including ethane, propane, butanes, and natural gasoline.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.
12
NYMEX. New York Mercantile Exchange.
Productive wells. Producing
wells and wells that are mechanically capable of production.
Proved developed reserves. Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. Quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the end of the reporting period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved undeveloped reserves or PUDs. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from
existing wells where a relatively major expenditure is required for recompletion.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Standardized measure or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and property taxes, future capital costs, operating expenses, and estimated future income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s
requirements, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the estimation date in accordance with the SEC’s regulations and are held constant for the life of the reserves.
Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Working interest. An operating interest which gives the owner the right
to drill, produce, and conduct operating activities on the property, and to receive a share of production.
WTI or West Texas Intermediate. A grade of crude oil used as a benchmark in oil pricing.
Available Information
Forest’s website address is http://www.forestoil.com. Available on our website, free of charge, are Forest’s
Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, reports on Forms 3, 4, and 5 filed on behalf of directors and officers, as well as amendments to these reports. These materials are available as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC.
Also posted on Forest’s website, and available in print upon written request of any shareholder addressed to the Secretary of Forest, at 707 17th Street, Suite 3600, Denver, Colorado80202, are Forest’s Corporate Governance
13
Guidelines, the charters for the Audit, Compensation, and Nominating and Corporate Governance committees of our Board of Directors, and codes of ethics for our directors and employees entitled “Code of Business Conduct and Ethics” and “Proper Business Practices Policy,” respectively.
Forward-Looking Statements
The information in this Annual Report on Form 10-K 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. 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;
•
operational
initiatives and their effect on our production, expenses, and 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;
•
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;
•
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. See “Competition,”“Industry Regulation,” and “Environmental and Climate Change Regulation” above, as well as Part I, Item 1A “Risk Factors,” Part II, Item 7 “Management’s
14
Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources,” and Part II, Item 7A “Quantitative and Qualitative Disclosures about Market Risk” for a description of various, but by no means all, factors that could materially affect our ability to achieve the anticipated results
described in the 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 Annual Report on Form 10-K 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.
Item 1A. Risk
Factors.
We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows, and results of operations, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations. Except where the context otherwise indicates, references to oil and natural gas in this section include natural gas liquids.
Oil and natural gas prices are volatile. Declines in commodity prices have
adversely affected, and in the future may adversely affect, our results of operations, cash flows, financial condition, access to the capital markets, the economic viability of our reserves, and our ability to reinvest in order to maintain or grow our asset base.
Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to a variety of factors that are beyond our control. Approximately 73% of our estimated proved reserves at December 31, 2013 were natural gas, causing us to be particularly dependent on prices for natural gas. Low commodity prices may mean that it will not be economical to drill or produce oil and natural gas from some of our existing properties, and we may be required to curtail, or stop completely, our production activities
in those areas. A decline in commodity prices may have numerous effects on our business, including the following:
•
impairing our financial condition, liquidity, or ability to fund planned capital expenditures;
•
limiting our access to sources of capital, such as equity and debt;
•
prohibiting
us from developing our current properties, or from growing our asset base; or
•
making it more difficult to pay interest and principal on our indebtedness and satisfy our other obligations.
We have substantial indebtedness, and we may incur more debt in the future. Our leverage may materially adversely affect our operations and financial condition.
Our level of debt may have several important effects on our business and operations; among other things, it may:
•
require us to use a significant portion of our cash flows to service the obligations, which could limit our flexibility in planning for and reacting to changes in our business, and reduce the amount available to reinvest in order to maintain or grow our asset base;
15
•
adversely affect the credit ratings assigned by third-party rating agencies, which have in the past, and may in the future, downgrade their ratings of our debt and other obligations;
•
limit our access to the capital markets;
•
increase
our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;
•
place us at a disadvantage compared to companies in our industry that have less debt and other financial obligations; and
•
make us more vulnerable to economic downturns, volatile oil, natural gas, and natural gas liquids prices, and adverse developments in our business.
A
higher level of debt increases the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be affected by oil, natural gas, and natural gas liquids prices, financial, business, domestic, and global economic conditions, governmental regulations and environmental regulations, and other factors, including the mix and quality of our assets and our ability to develop and produce them. Many of these factors are beyond our control.
Over the past few years we have sold a significant amount of developed and undeveloped assets, and used the proceeds to reduce outstanding indebtedness. Despite these efforts, our debt remains relatively high in comparison to our remaining operating cash flows and assets. Our cash flows from our remaining assets may not be sufficient
to service our debt and other obligations or to meet the financial or other restrictive covenants contained in our bank credit facility and the indentures governing our outstanding senior notes. As a result, we may be required, if possible, to refinance or restructure the debt, sell additional assets, or sell shares of our common or preferred equity securities — all on terms that we do not find attractive. We also may be required to reduce expenses by curtailing operations.
The governing documents of our debt instruments contain covenants and restrictions that require us to meet certain financial tests and place restrictions on the incurrence of additional indebtedness. A failure on our part to comply with the financial and other restrictive covenants contained in our bank credit facility
and the indentures governing our outstanding senior notes could result in a default under these agreements. Any default under our bank credit facility or indentures could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future. In addition, if not waived by the relevant lenders, a default could lead to foreclosure of our assets, which in turn could result in bankruptcy.
We may not be able to obtain funding under our current bank credit facility because of a decrease in our borrowing base or obtain funding in the capital markets on terms we find acceptable.
Historically,
we have used our cash flows from operations and borrowings under our bank credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions or to refinance debt obligations. We currently have a bank credit facility with lender commitments totaling $1.5 billion. The borrowing base is determined by the lenders periodically and is based on the estimated value of our properties using pricing models determined by the lenders at such time. The current borrowing base was set at $400 million in connection with the closing of the sale of our assets in the Texas Panhandle on November 25, 2013. The next scheduled redetermination of the borrowing base will occur on or before May
1, 2014, at which time our borrowing base may be further reduced. Also, under the terms of our bank credit facility, our borrowing base will be immediately decreased by an amount equal to 25% of the stated principal amount of senior notes issued in the future (excluding any senior notes that we may issue to refinance senior notes that were outstanding on June 30, 2011). In the future, we may not be able to access adequate funding under our bank credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Since the process for determining the borrowing base under our
16
bank
credit facility involves evaluating the estimated value of our oil and natural gas properties using pricing models determined by the lenders at that time, a decline in those prices used, or further downward reductions of our reserves, likely will result in a redetermination of our borrowing base and a decrease in the available borrowing amount at the time of the next scheduled redetermination. In such case, we would be required to repay any indebtedness in excess of the borrowing base.
Volatility in the public and private capital markets may make it more difficult to obtain funding. There is a risk that the cost of obtaining money from the credit markets may increase in the future as lenders and institutional investors may increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity on terms similar to existing debt or at all, or reduce
or cease to provide any new funding. Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.
Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.
Our bank credit facility and the indentures
governing our senior notes contain restrictive covenants that limit our ability and the ability of certain of our subsidiaries to, among other things:
•
incur or guarantee additional indebtedness or issue preferred shares;
•
pay dividends or make other distributions;
•
purchase
equity interests or redeem subordinated indebtedness early;
•
create or incur certain liens;
•
enter into transactions with affiliates; and
•
sell
assets or merge or consolidate with another company.
Complying with the restrictions contained in some of these covenants will require us to meet certain financial ratios and tests, notably with respect to consolidated interest coverage, total assets, net debt, equity, and net income. For example, our bank credit facility provides that we will not permit our ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended to be greater than a specified amount. In September 2013, we amended the facility to increase the permitted ratio to 5.0 to 1.0 for any time after September 11, 2013 up to and including March 31, 2014, and to 4.75 to 1.0 for any time after April
1, 2014 up to and including June 30, 2014. After June 30, 2014, the ratio returns to the original restriction of 4.5 to 1.0. Our ratio of total debt to EBITDA for the four consecutive fiscal quarter period ending December 31, 2013, as calculated in accordance with our bank credit facility, was 4.3. Our need to comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, or withstand a future downturn in our business. Based on our current projections, absent an amendment to the bank credit facility, we expect the ratio of total debt to EBITDA to exceed the maximum allowed sometime during the
second or third quarter of 2014. Non-compliance with the terms of our debt covenants or other credit provisions could result in all amounts outstanding under our bank credit facility and, potentially, our indentures, becoming due and payable immediately, and the resultant termination of our bank credit facility. This would result, at a minimum, in the need to slow or cease the incurrence of capital and operational expenditures, which would have a negative impact on our expected production, revenues and, potentially, on our reserves. At worse, it could also result in foreclosure of our assets and potential bankruptcy. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a more complete discussion of our debt obligations and liquidity.
17
We are a relatively small company and therefore may not be able to compete effectively.
Compared to many of our competitors in the oil and gas industry, we are a very small company. We face difficulties in competing with larger companies. The costs of doing business in the exploration and production industry, including such costs as those required to explore new oil and natural gas plays, to acquire new acreage, and to develop attractive oil and natural gas projects, are significant. We face intense competition in all areas of our business from companies with greater and more productive assets, substantially larger staffs, and greater financial and operating resources than we have. In addition, legacy costs associated with our relatively long period
of existence may result in our operating costs being greater than competitors of similar size. Our limited size has placed us at a disadvantage with respect to funding our operating costs, and means that we are more vulnerable to commodity price volatility and overall industry cycles, are less able to absorb the burden of changes in laws and regulations, and that poor results in any single exploration, development, or production play can have a disproportionately negative impact on us.
We also compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Our limited size has placed us at a disadvantage with respect to attracting and retaining management and other professionals with the technical abilities necessary to successfully operate our business. For instance, since the beginning of 2013 alone, three executive officers resigned
their positions with Forest, and Forest’s employee resignation rate was 16% per annum versus the historic norm of 10%. Continued difficulty in retaining quality personnel may have a negative impact on our operations.
Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves and our financial condition.
The proved oil and natural gas reserves information and the related future net revenues information included in this Annual Report on Form 10-K and in our other periodic reports represent only estimates, which are prepared by our internal staff of engineers and the majority of which are audited by DeGolyer and MacNaughton, an independent petroleum engineering firm. Estimating quantities of
proved oil and natural gas reserves is a complex, inexact process and depends on a number of interpretations of technical data and various factors and assumptions, including assumptions required by the SEC as to oil, natural gas, and natural gas liquids prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. As a result, these estimates are inherently imprecise. Any significant inaccuracies or changes in our assumptions or changes in operating conditions could cause the estimated quantities and net present value of the estimated reserves to be significantly different.
At December 31, 2013, approximately 34% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves
generally requires significant capital expenditures and successful drilling operations. Our reserves estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated.
Our estimated proved reserves as of December 31, 2013 were based on a NYMEX HH price of $3.67 per MMBtu for natural gas and a NYMEX WTI price of $97.33 per barrel for oil, each of which represents the unweighted arithmetic average of the first-day-of-the month prices during the twelve-month period prior to December 31,
2013, and an average realization for a barrel of natural gas liquids during that period equal to approximately 31% of the NYMEX WTI price or $29.93. For the year ended December 31, 2012, the comparable prices used to calculate our estimated proved reserves were $2.76 per MMBtu for natural gas, $94.79 per barrel for oil, and an average realization for a barrel of natural gas liquids equal to approximately 36% of the oil price or $33.83. Despite the increase in prices from those used to estimate proved reserves as of December 31, 2012, which resulted in positive reserve revisions of 40 Bcfe during 2013, we revised
our estimated proved reserves downward during 2013 by 41 Bcfe due to the reclassification of proved undeveloped reserves (“PUDs”) to probable undeveloped reserves for PUDs that are not expected to be developed five years from the time the reserves were initially disclosed and by 9 Bcfe due to negative performance revisions. We may be required to make further downward revisions in our proved reserves in the future. You should not assume that any present value of future net
18
cash flows from our estimated proved reserves as set forth in this Annual Report on Form 10-K for the year ended December 31,
2013 represents the market value of our oil and natural gas reserves.
Lower oil, natural gas, and natural gas liquids prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.
We use the full cost method of accounting to report our oil and natural gas activities. Under this method, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and natural gas properties may not exceed a ceiling limit, which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and natural
gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a ceiling test write-down. Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down does not impact cash flows from operating activities, but it does reduce our shareholders’ equity.
Investments in unproved properties also are assessed periodically 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, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized, or is reported as a period expense, as appropriate. If an impairment of unproved properties is added
to the costs to be amortized, the amount by which the ceiling limit exceeds the capitalized costs of proved oil and natural gas properties is reduced.
We also assess the carrying amount of goodwill in the second quarter of each year and at other periods when events occur that may indicate an impairment exists. These events include, for example, a decline in our market capitalization relative to our net asset values or other adverse economic or qualitative factors.
The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil, natural gas, and natural gas liquids prices are low. In addition, write-downs may occur if we experience downward adjustments to our estimated proved reserves or our unproved property values, or if estimated
future development or operating costs increase. For example, during 2013 we incurred a ceiling test write-down of $58 million. 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 oil, natural gas, and natural gas liquids prices used in the calculation of the present value of future net revenue from estimated production of estimated proved reserves decline compared to prices used as of December 31, 2013, unproved property values are impaired, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable
to the cost center.
If we are not able to replace reserves, we will not be able to sustain or grow production.
In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we replace the reserves we produce through successful development, exploration or acquisition, our proved reserves and production will decline over time.
We do not always find commercially productive reserves through our drilling operations. The seismic data and other technologies that we use when drilling wells do not allow us to determine conclusively prior to drilling a well whether oil or natural gas
is present or can be produced economically. Moreover, the costs of drilling, completing, and operating wells are often uncertain. Our drilling activities, therefore, may result in the total loss of our investment or a return on investment significantly below expectation.
19
Much of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
Approximately 43% of our net acreage located in the United States is currently undeveloped. Unless production
in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans are subject to change based upon various factors, including drilling results, oil and natural gas prices, cash flow, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. We cannot be sure that we will be able to maintain all of our leased properties by initiating production. Any such loss of properties could reduce our access to capital and have a negative impact on our operations.
The marketability of our production is dependent upon gathering, transportation, and processing facilities over which we may have
no control.
We deliver the majority of our oil and natural gas through gathering facilities that we do not own or operate. As a result, we are subject to the risk that these facilities may be temporarily unavailable due to mechanical reasons or market conditions, or may not be available to us in the future. These issues can result in wells being shut in or in us receiving lower prices for our production. If we experience interruptions or loss of pipeline capacity or access to gathering systems that impact a substantial amount of our production, it could have an adverse impact on our operations and cash flow. We are subject to similar risks with respect to processing facilities and other midstream infrastructure and services.
Drilling is a high-risk activity that could result in substantial
losses for us.
Drilling activities are subject to many risks, including well blow-outs, cratering and explosions, pipe failures, fires, uncontrollable flows of oil, natural gas, brine, or well fluids, other environmental hazards, and risks outside of our control, including, among other things, the risk of natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources, and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. We maintain insurance against some, but not all, of the risks described above. Generally, pollution-related environmental risks are not fully insurable. We do not insure against business interruption. We cannot assure that
our insurance will be fully adequate to cover other losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.
Our use of hedging transactions could reduce our cash flow and/or result in reported losses.
We periodically enter into hedging agreements for a portion of our anticipated oil, natural gas, and natural gas liquids production. Our commodity hedging agreements are limited in duration, usually for periods of one year or less; however, we sometimes enter into hedges for longer periods. Should commodity prices increase after we have entered into a hedging transaction, our cash flows will be lower than they would have been without the hedging transaction.
For
financial reporting purposes, we do not use hedge accounting, thus we are required to record changes in the fair value of our hedging instruments through our earnings rather than through other comprehensive income, as would be the case had we elected to use hedge accounting. As a consequence, we may report material changes in fair value, or unrealized losses or gains, on our hedging agreements prior to their expiry. The amount of the actual cash settlements, or realized losses or gains, will differ and will be based on the actual prices of the commodities on the settlement dates as compared to the hedged prices contained in the hedging agreements. As a result, our periodic financial results will be subject to fluctuations related to our derivative instruments.
Moreover, our hedging program may be limited due to certain regulatory constraints. The Dodd-Frank Wall Street Reform
and Consumer Protection Act, among other things, imposes requirements and oversight on hedging
20
transactions, including clearing and margin requirements under certain circumstances. While certain of the implementing regulations are yet to be finalized by the relevant federal agencies, to the extent that they are applicable to us or our counterparties, we may incur increased costs and cash collateral requirements that could affect our ability to hedge risks associated with our business.
We may incur significant costs related to environmental and other governmental laws and regulations, including those related to “hydraulic fracturing,”
that may materially affect our operations.
Our oil and natural gas operations are subject to various U.S. federal, state, and local laws and regulations, and local and national laws and regulations in Italy and South Africa. Many of the laws and regulations to which our operations are subject include those relating to the protection of the environment. We could incur material costs, including clean-up costs, fines, and civil and criminal sanctions and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, present or future environmental laws and regulations.
We routinely utilize hydraulic fracturing, which is an important and common practice used to stimulate production of hydrocarbons from tight or low-permeability formations. State
oil and gas commissions typically regulate the process. However, several federal entities, including the EPA, have also recently asserted potential regulatory authority over hydraulic fracturing. Most notably, the EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. A draft report is expected sometime in 2014. Some states, such as Texas, have adopted, and some states, including others in which we operate, are considering adopting, regulations that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing operations. Some local governmental bodies have adopted or are considering adopting similar regulations. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to operate. Restrictions on, or increased costs of, hydraulic fracturing
could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Recently proposed or finalized rules and guidance imposing more stringent requirements on the oil and gas exploration and production industry could cause us to incur increased capital expenditures and operating costs as well as decrease our levels of production.
Federal, state, and local regulatory developments could adversely impact our operations in a variety of ways, including by causing us to incur increased capital expenditures and costs. For example, on April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas
liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions
from dehydrators, storage tanks, and other production equipment. The EPA currently is reconsidering parts of these air rules, with expected finalization in November 2014. Compliance with these requirements could increase our costs of development and production, which costs may be significant.
In addition, federal agencies have recently announced at least two other regulatory initiatives regarding certain aspects of hydraulic fracturing that could further increase our costs to operate and decrease our levels of production. On May 4, 2012, the U.S. Department of the Interior (“DOI”) announced proposed rules that, if adopted, would require disclosure of chemicals used in hydraulic fracturing activities upon federal and Indian lands and also would strengthen standards for well-bore integrity and the management of fluids that
return to the surface during and after fracturing operations on federal and Indian lands. The DOI has not yet finalized these rules. Also on May 4, 2012, the EPA issued draft guidance for federal Safe Drinking Water Act permits issued to oil and natural gas exploration and production operators using diesel during hydraulic fracturing. The EPA has not yet finalized this
21
guidance. The adoption or implementation of these regulatory initiatives could cause us to incur increased expenditures and decrease our levels of production.
The credit risk of financial institutions could adversely affect
us.
We have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies, and their affiliates. These transactions expose us to credit risk in the event of default of our counterparty, principally with respect to hedging agreements but also insurance contracts and bank lending commitments. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. See Note 9 to the Consolidated Financial Statements included in this Annual Report for a more complete discussion of credit risk with respect to our derivative instruments.
New
Risk Factors in this Form 10-K/A
We may not be able to continue as a going concern.
The financial statements included in this Form 10-K/A have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. Forest previously disclosed in its unreviewed Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August
18, 2014, that by year end 2014 the ratio of its total debt to EBITDA may exceed the maximum allowed under its bank credit facility unless it undertakes certain mitigating actions. Absent such actions, a resultant breach of the financial covenant could cause a default under the Credit Facility, potentially resulting in an acceleration of all amounts outstanding under the Credit Facility as well as our senior unsecured notes due 2019 and 2020. As of September 30, 2014, we had approximately $13 million outstanding under the Credit Facility and $800 million in principal amount outstanding under the notes. Acceleration of debt of this magnitude likely would result in our bankruptcy or other restructuring.
On
May 5, 2014, we entered into an Agreement and Plan of Merger with Sabine Oil & Gas LLC (“Sabine”), under which Forest and Sabine are expected to combine their businesses in an all-stock transaction. This agreement was amended on July 9, 2014 primarily to change the structure of the transaction. If the transaction is completed, Forest’s credit facility will be terminated before any breach of the covenant occurs. Accordingly, we have elected to defer seeking an amendment or waiver to address a potential breach rather than incurring the expense of doing so at the present time solely to avoid a “going concern” audit opinion. If, prior to year end, it appears the combination transaction will not be completed, Forest will again evaluate the likelihood of a breach of the
financial covenant and, based on that evaluation, attempt to undertake mitigating actions with respect to the bank credit facility that it feels are most appropriate. However, there can be no assurance that any particular actions will be available to Forest, or that even if available, Forest will be able to complete them. If the combination transaction is not completed, failure to take appropriate mitigating actions in the event we are in breach of the covenant may have severely negative effects on our financial condition including, potentially, bankruptcy.
We have identified material weakness in our internal control over financial reporting at December 31, 2013. Our failure to establish and maintain effective internal control over financial reporting could result in material misstatements in our financial statements, and our
failure to meet our reporting and financial obligations, which in turn could have a negative impact on our financial condition.
Maintaining effective internal control over financial reporting is necessary for us to produce reliable financial statements. As more fully disclosed in Item 9A. “Controls and Procedures,” subsequent to the filing of the Original Filing, the Public Company Accounting Oversight Board (the “PCAOB”) conducted an inspection of audits conducted by EY of our internal control over financial reporting as of December 31, 2013, and the financial statements included in the Original Filing. Following this inspection, EY requested a reevaluation of certain control
22
deficiencies that had been previously identified. In addition, EY and Forest’s management conducted additional analyses of other issues relating to Forest’s internal controls. We have now concluded that certain material weaknesses existed in Forest’s internal control over financial reporting as of December 31, 2013.
Under standards established by the PCAOB, a material weakness is defined as a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Under the criteria set forth in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework), a material weakness in the design of monitoring controls indicates that we have not sufficiently developed and/or documented (i.e. designed) internal controls by which management can review and oversee (i.e. monitor) our financial information to detect and correct material errors or that the personnel responsible for performing the review did not have the sufficient skill set or knowledge of the subject matter to perform a proper assessment.
We have adopted and partially implemented a plan to remediate the material weaknesses that have been identified. However, we can give no assurance that the measures we take will remediate the material weaknesses or that additional material weaknesses will not arise in the future. Any failure to remediate the material weaknesses, or the development
of new material weaknesses in our internal control over financial reporting, could result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a negative impact on our financial condition.
Item 1B. Unresolved Staff Comments.
As of December 31, 2013, we did not have any SEC staff comments regarding our periodic or current reports that have been unresolved for 180 days or more.
Item 2. Properties.
Information
on Properties is contained in Item 1 of this Annual Report on Form 10-K.
Item 3. Legal Proceedings.
On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al., which occurred in Harris County, Texas. The third member of the arbitration panel dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by
Forest in the 1970s, 1980s, and early 1990s. The arbitration decision awards the claimant $23 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest is seeking to have this judgment reversed on appeal and believes it has meritorious arguments in support thereof.
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
23
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. Forest believes that these claims are without merit and intends to defend the claim against it vigorously.
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 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Common Stock
Forest has one class of common shares
outstanding, its common stock, par value $.10 per share (“Common Stock”). Forest’s Common Stock is traded on the New York Stock Exchange under the symbol “FST.” On February 19, 2014, our Common Stock was held by 587 holders of record. The number of holders does not include the shareholders for whom shares are held in a “nominee” or “street” name.
The table below reflects the high and low intraday sales prices per share of the Common Stock on the New York Stock Exchange composite tape. There were no cash dividends declared on the Common Stock in 2012 or 2013. On February 19,
2014, the closing price of Forest Common Stock was $3.22.
Common Stock
High
Low
2012
First
Quarter
$
15.15
$
11.61
Second Quarter
13.69
6.22
Third
Quarter
9.32
5.68
Fourth Quarter
9.12
6.06
2013
First
Quarter
$
7.44
$
5.18
Second Quarter
5.43
3.77
Third
Quarter
6.67
4.02
Fourth Quarter
6.52
3.43
Dividend
Restrictions
Forest’s present or future ability to pay dividends is governed by (i) the provisions of the New York Business Corporation Law, (ii) Forest’s Restated Certificate of Incorporation and Bylaws, (iii) the indentures
24
governing Forest’s 7¼% senior notes due 2019 and 7½% senior notes due 2020 and (iv) Forest’s bank credit facility dated as of June
30, 2011, as amended. The provisions in the indentures pertaining to these senior notes and in the bank credit facility limit our ability to make restricted payments, which include dividend payments. On September 30, 2011, Forest distributed a special stock dividend in connection with the spin-off of Lone Pine; however, Forest has not paid cash dividends on its Common Stock during the past five years. The future payment of cash dividends, if any, on the Common Stock is within the discretion of the Board of Directors and will depend on Forest’s earnings, capital requirements, financial condition, and other relevant factors. There is no assurance that Forest will pay any cash dividends. For further information regarding our equity securities, our ability to pay dividends on our Common
Stock, and the spin-off of Lone Pine, see Notes 3 and 5 to the Consolidated Financial Statements.
Unregistered Sales of Equity Securities
We did not make any sales of unregistered equity securities during the quarter ended December 31, 2013.
Issuer Purchases of Equity Securities
The table below sets forth information regarding repurchases of our Common Stock during the quarter ended December 31, 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
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
October 2013
89,653
$
5.35
—
—
November
2013
40,612
4.29
—
—
December 2013
3,116
3.76
—
—
Fourth
Quarter Total
133,381
$
4.99
—
—
25
Stock Performance Graph
The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2008 (and the reinvestment of dividends thereafter) in each of Forest Common Stock, the S&P 500 Index, and the Dow Jones U.S. Exploration and Production Index. We believe that the Dow Jones U.S. Exploration and Production Index is meaningful because it is an independent, objective view of the performance of other similarly-sized energy companies.
Comparison Of 5 Year Cumulative Total Return*
Among Forest Oil Corporation, the S&P
500 Index,
and the Dow Jones US Exploration & Production Index
*$100 invested on 12/31/08 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.
The information in this Annual Report on Form 10-K appearing under the heading “Stock Performance Graph” is being furnished pursuant to Item 201(e) of Regulation S-K and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of
Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.
26
Item 6. Selected Financial Data.
The following table sets forth selected financial and operating data of Forest as of and for each of the years in the five-year period ended December 31, 2013. This data should be read in conjunction with Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated
Financial Statements and Notes thereto contained elsewhere in this report. We have completed several oil and gas property divestitures that affect the comparability of the results for the years presented below. See Part I, Item 1 “Business—Acquisition and Divestiture Activities” and Note 2 to the Consolidated Financial Statements for more information on divestitures.
Oil, natural
gas, and natural gas liquids sales(1)
$
441,341
$
605,523
$
703,531
$
707,692
$
655,579
Net
earnings (loss) from continuing operations
$
73,924
$
(1,288,931
)
$
98,260
$
189,662
$
(793,789
)
Net
earnings (loss) from discontinued operations(2)
—
—
44,569
37,859
(129,344
)
Net
earnings (loss)
73,924
(1,288,931
)
142,829
227,521
(923,133
)
Less:
net earnings attributable to noncontrolling interest(2)
—
—
4,987
—
—
Net
earnings (loss) attributable to Forest Oil Corporation common shareholders
$
73,924
$
(1,288,931
)
$
137,842
$
227,521
$
(923,133
)
Basic
earnings (loss) per common share attributable to Forest Oil Corporation common shareholders:
Earnings (loss) from continuing operations
$
.62
$
(11.21
)
$
.86
$
1.68
$
(7.61
)
Earnings
(loss) from discontinued operations
—
—
.35
.33
(1.24
)
Basic
earnings (loss) per common share attributable to Forest Oil Corporation common shareholders
$
.62
$
(11.21
)
$
1.21
$
2.01
$
(8.85
)
Diluted
earnings (loss) per common share attributable to Forest Oil Corporation common shareholders:
Earnings (loss) from continuing operations
$
.62
$
(11.21
)
$
.85
$
1.67
$
(7.61
)
Earnings
(loss) from discontinued operations
—
—
.34
.33
(1.24
)
Diluted
earnings (loss) per common share attributable to Forest Oil Corporation common shareholders
$
.62
$
(11.21
)
$
1.19
$
2.00
$
(8.85
)
Total
assets(1)
$
1,117,952
$
2,201,862
$
3,381,151
$
3,070,197
$
3,169,054
Long-term
debt(1)
$
800,179
$
1,862,100
$
1,693,044
$
1,869,372
$
2,022,514
Shareholders’
equity (deficit)
$
54,469
$
(42,824
)
$
1,193,113
$
1,352,787
$
1,079,154
OPERATING
DATA(1)
Annual production:
Oil
(MBbls)
2,271
3,146
2,491
2,357
3,397
Natural
gas (MMcf)
46,676
81,008
88,497
101,346
116,029
NGLs
(MBbls)
2,521
3,489
3,154
3,589
3,012
Average
sales price:
Oil (per Bbl)
$
96.30
$
96.14
$
96.22
$
76.08
$
56.87
Natural
gas (per Mcf)
$
3.16
$
2.37
$
3.71
$
3.99
$
3.33
NGLs
(per Bbl)
$
29.79
$
31.77
$
42.91
$
34.54
$
25.17
____________________________________________
(1)
Amounts
reported relate to continuing operations only. See below for more information regarding discontinued operations.
27
(2)
On June 1, 2011, Forest completed the initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone Pine Resources Inc., which held Forest’s ownership interests in its Canadian operations. On September 30,
2011, Forest distributed, or spun-off, the remaining 82% of Lone Pine by means of a special stock dividend to Forest’s shareholders. Lone Pine’s results are reported as discontinued operations throughout this Annual Report on Form 10-K.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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 in Part I, Item 1 under the heading
“Forward-Looking Statements.” Our actual results may differ materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed in Part I, Item 1A “Risk Factors,” and elsewhere in this Annual Report on Form 10-K. Historical statements made herein are accurate only as of the date of filing of this Annual Report on Form 10-K with the SEC, and may be relied upon only as of that date. The following discussion and analysis should be read in conjunction with Forest’s Consolidated Financial Statements and Notes thereto.
Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids 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. Our total estimated proved reserves as of December 31, 2013 were approximately 625 Bcfe, all of which are located in our one reportable geographical segment - the United States. Our core operational areas are in Eagle Ford in South Texas and Ark-La-Tex in Texas, Louisiana, and Arkansas. See Item 1 “Business” for a discussion of our business strategy and core operational areas of focus.
2013 Highlights
Forest’s 2013 highlights were as follows:
•
Reduced
the outstanding principal of our long-term debt by $1.1 billion.
•
Received cash proceeds of $1.3 billion from the property divestiture program we initiated in 2012, including $321 million for the South Texas divestiture and $965 million for the Panhandle divestiture.
•
Increased
total oil and NGL sales volumes to 38% of total equivalent sales volumes compared to 33% in 2012 and 28% in 2011. Pro forma for property divestitures in 2012 and 2013, total oil and NGL sales volumes were 29% of total equivalent sales volumes in 2013 compared to 19% in 2012.
•
Entered into an agreement with a third-party for the development of our Eagle Ford acreage in South Texas. Under the terms of the agreement, the third-party will pay a $90 million drilling carry in exchange for a 50% working interest in our Eagle Ford acreage position. We are the operator
of the drilling program. As of December 31, 2013, we had realized $61 million of the drilling carry.
•
Increased Eagle Ford average net sales volumes by 62% over 2012 to approximately 2,550 boe/d.
•
Reduced drilling and completion costs per well in the Eagle Ford by 15% over 2012.
Results
of Operations
Forest recorded net earnings in 2013 of $74 million as compared to a net loss of $1.3 billion in 2012. Net earnings in 2013 included a $193 million net gain recognized on the sale of our assets in the Texas Panhandle, a $49 million loss on the early extinguishment of debt, $31 million in unrealized losses on derivative instruments, and a $58 million ceiling test write-down. The net loss in 2012 was primarily due to ceiling test write-downs and other non-cash property impairments totaling $1.1 billion as well as a $245 million valuation allowance
placed against net deferred tax assets primarily as a result of the ceiling test write-downs and property impairments recognized in 2012. See “Critical Accounting Policies, Estimates, Judgments and Assumptions—Valuation of Deferred Tax Assets” for
28
further discussion of our valuation allowance. The 2012 net loss also included $39 million in unrealized losses on derivative instruments and a $36 million loss on the early extinguishment of debt.
Adjusted EBIDTA, which is a performance measure not calculated
in accordance with generally accepted accounting principles (“GAAP”), is commonly used by management, securities analysts, and investors and excludes non-cash items such as depletion expense, deferred income tax expense, and ceiling test write-downs. Our Adjusted EBITDA was $333 million in 2013 as compared to $514 million in 2012. The decrease of $181 million was primarily attributable to property divestitures during 2013, which reduced revenues and, to a lesser extent, reduced production expense. See “Reconciliation of Non-GAAP Measure” at the end of this Item 7 for a reconciliation of Adjusted EBITDA to net earnings (loss) from continuing operations, the most directly comparable financial measure calculated and presented in accordance with GAAP.
During
2013, we completed two large oil and natural gas property divestitures, as discussed in Part I, Item 1 “Business—Acquisition and Divestiture Activities” and Note 2 to the Consolidated Financial Statements. Because of these divestitures, we anticipate that our 2014 oil, natural gas, and natural gas liquids sales volumes, revenues, and production expense will be lower as compared to 2013. Additionally, we expect 2014 interest expense and general and administrative expense to be lower as compared to 2013 due to less debt and fewer employees, respectively.
Oil, Natural Gas, and Natural Gas Liquids Volumes and Revenues
Oil, natural gas, and natural gas liquids sales volumes, revenues, and per unit price realizations from
continuing operations for the years ended December 31, 2013, 2012, and 2011, are set forth in the table below.
We have divested a substantial amount of oil and natural gas properties in recent years, causing significant changes
from period to period in our oil, natural gas, and NGL revenues and sales volumes and causing historical amounts reported to be not necessarily indicative of future results. Accordingly, the tables below distinguish oil, natural gas, and NGL sales revenues and volumes, as well as per unit price realizations, between the South Louisiana, South Texas, and Texas Panhandle oil and natural gas properties (the “Divested properties”) we divested in November 2012, February 2013, and November 2013, respectively, and those oil and natural gas properties that we continued to own as of December 31, 2013 (the “Retained properties”).
Certain
amounts may not recalculate due to rounding.
(2)
The change in revenues attributable to the change in volumes is calculated as the product of (i) the per unit price realization for the year ended December 31, 2012 and (ii) the change in volumes between the year ended December 31, 2012 and the year ended December 31, 2013. Certain amounts do not foot due to rounding.
(3)
The
change in revenues attributable to the change in prices is calculated as the product of (i) the volumes for the year ended December 31, 2013 and (ii) the change in the per unit price realization between the year ended December 31, 2012 and the year ended December 31, 2013. Certain amounts do not foot due to rounding.
Equivalent sales volumes were 75.4 Bcfe in 2013 as compared to 120.8 Bcfe in 2012. The 45.4 Bcfe, or 38%, decrease in equivalent
sales volumes in 2013 compared to 2012 was primarily due to the divestitures of producing oil and natural gas properties in South Louisiana, South Texas, and the Texas Panhandle, which accounted for 41.7 Bcfe of the decrease. Equivalent sales volumes attributable to properties we continued to own as of December 31, 2013 decreased 8% to 41.0 Bcfe in 2013 from 44.7 Bcfe in 2012. The 8% decrease in these equivalent sales volumes was due to a 20% decrease in natural gas production offset by a 55% increase in oil production and a 23% increase in NGL production. The increase in oil production was a result of our development efforts in the Eagle Ford,
where we incurred approximately $108 million in direct exploration, development, and leasehold acquisition capital expenditures in 2013, and the increase in NGL production was due to our drilling program in East Texas, where we incurred approximately $80 million in direct exploration, development, and leasehold acquisition capital expenditures in 2013. Natural gas production declined 20% due to the natural decline in production from existing wells that exceeded the incremental natural gas production we added in 2013 from drilling liquids-rich East Texas wells.
Revenues from oil, natural gas, and NGLs were $441 million in 2013 as compared to $606 million in 2012.
The $164 million, or 27%, decrease in revenues in 2013 compared to 2012 was primarily due to the divestitures of producing oil and natural gas properties in South Louisiana, South Texas, and the Texas Panhandle, which accounted for $217 million of the decrease. This decrease was moderated by a 5% increase between the respective periods in the per unit equivalent price realized from these properties while we owned them. Revenues from the properties we continued to own as of December 31, 2013 increased $53 million primarily due to increased liquids production as discussed above and a 39% increase in the
equivalent price realized between the two periods.
Certain
amounts may not recalculate due to rounding.
(2)
The change in revenues attributable to the change in volumes is calculated as the product of (i) the per unit price realization for the year ended December 31, 2011 and (ii) the change in volumes between the year ended December 31, 2011 and the year ended December 31, 2012. Certain amounts do not foot due to rounding.
(3)
The
change in revenues attributable to the change in prices is calculated as the product of (i) the volumes for the year ended December 31, 2012 and (ii) the change in the per unit price realization between the year ended December 31, 2011 and the year ended December 31, 2012. Certain amounts do not foot due to rounding.
Equivalent sales volumes were 120.8 Bcfe in 2012 as compared to 122.4 Bcfe in 2011. The 1.5 Bcfe, or 1%, decrease in equivalent
sales volumes in 2012 compared to 2011 consisted of a decrease of 6.7 Bcfe attributable to the Divested properties, partially offset by a 5.1 Bcfe increase attributable to properties we continued to own as of December 31, 2013. The 5.1 Bcfe increase attributable to properties we continued to own as of December 31, 2013 was comprised of a 3.9 Bcfe, or 85%, increase in liquids production and a 1.2 Bcfe, or 3%, increase in natural gas production in 2012 as compared to 2011. The increase in oil production was a result of our development efforts in the Eagle Ford, where we incurred approximately $141 million in direct exploration, development, and leasehold acquisition capital expenditures in 2012, and the increase in NGL production was due to our drilling program in East Texas, where
we incurred approximately $94 million in direct exploration, development, and leasehold acquisition capital expenditures in 2012.
Revenues from oil, natural gas, and NGLs were $606 million in 2012 as compared to $704 million in 2011. The $98 million, or 14%, decrease in revenues in 2012 compared to 2011 consisted of a decrease of $106 million attributable to the Divested properties, partially offset by a $8 million increase attributable to properties we continued to own as of December 31,
2013. The $8 million increase attributable to properties we continued to own as of December 31, 2013 was due to the increase in sales volumes, as discussed above, as well as a 9% increase in the per unit price realized for oil. These increases were partially offset by decreases of 33% and 24% in the per unit prices realized for natural gas and NGLs, respectively.
The revenues and per unit price realizations reflected in the tables above exclude the effects of commodity derivative instruments because we have elected not to designate our derivative instruments as cash flow hedges. See
31
“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 from continuing operations for the periods indicated.
We have divested a substantial amount of oil and natural gas properties in recent years, causing significant
changes from period to period in our lease operating expenses, production and property taxes, and transportation and processing costs and causing historical amounts reported to be not necessarily indicative of future results. Accordingly, the tables below distinguish lease operating expenses, production and property taxes, and transportation and processing costs, as well as per unit production expense, between the South Louisiana, South Texas, and Texas Panhandle oil and natural gas properties (the “Divested properties”) we divested in November 2012, February 2013, and November 2013, respectively, and those oil and natural gas properties that we continued to own as of December 31, 2013 (the “Retained properties”).
Lease operating expenses in 2013 were $77 million, or $1.02 per Mcfe, compared to $108 million, or $.89 per Mcfe, in 2012. Lease operating expenses decreased $31 million in 2013 compared to 2012 with such decrease comprised of $43 million due to the divestitures of the Divested properties, partially offset by an
increase in lease operating expenses of $11 million attributable to the Retained properties. Lease operating expenses on the Retained properties increased primarily due to increases in chemical treatment costs, saltwater disposal costs, workovers, and overhead. Chemical treatment and saltwater disposal costs, which relate primarily to our Eagle Ford oil properties, increased approximately $4 million from 2012 to 2013. Workover expense increased approximately $3 million from 2012 to 2013 primarily due to a workover program implemented in East Texas. Overhead increased approximately $3 million from 2012 to 2013. The increase in per-unit lease operating expenses is primarily due to a higher percentage of oil production as a percentage of total equivalent production. Based on the energy-equivalent ratio of six Mcf of natural gas to one barrel of oil, oil production typically has higher per-unit lease operating costs than does
natural gas production. However, because the market price of oil relative to natural gas is currently well in excess of the six-to-one ratio, the increase in lease operating expense associated with an increase in oil production is more than offset by the additional revenues realized from oil sales.
Lease operating expenses were $108 million, or $.89 per Mcfe, in 2012 compared to $99 million, or $.81 per Mcfe, in 2011. Lease operating expenses increased $9 million in 2012 compared to 2011, with $6 million of
this increase attributable to the Retained properties and $3 million attributable to the Divested properties. Lease operating expenses increased on the Retained properties primarily due to increased chemical treatment and saltwater disposal costs of approximately $4 million and increased fuel, power, and water costs of approximately $1 million, the majority of such costs being related to our Eagle Ford oil properties. Lease operating expenses increased on the Divested properties primarily due to increases in workover expense of approximately $4 million and compressor rental expense of approximately $2 million, partially offset by smaller decreases in miscellaneous lease operating costs.
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 3.4%, 5.7%, and 5.8% of oil, natural gas, and NGL sales for the years ended December 31, 2013, 2012, and 2011, respectively. Production and property taxes as a percentage of oil, natural gas, and NGL sales for the Retained properties were 4.3%, 4.7%, and 3.7% for the years ended December 31, 2013, 2012, and 2011, respectively. Normal fluctuations
occur in this percentage between periods based upon changes in tax rates, including those changes caused by incentive tax credits earned, and changes in the assessed values of oil and natural gas properties and equipment for purposes of ad valorem taxes.
Transportation and Processing Costs
Transportation and processing costs were $12 million, or $.16 per Mcfe, in 2013, $15 million, or $.12 per Mcfe, in 2012, and $14 million, or $.11
per Mcfe, in 2011. Transportation and processing costs decreased $3 million from 2012 to 2013, with $2 million of this decrease being due to the divestitures of the Divested properties. Transportation and processing costs on the Retained properties remained relatively stable between the two years, with 2013 showing a slight decrease. Transportation and processing costs increased $1 million from 2011 to 2012, with $2 million of this increase attributable to the Retained properties, partially offset by a $1 million decrease attributable to the Divested properties.
34
General and Administrative Expense
The following table summarizes the components of general and administrative expense from continuing operations for the periods indicated.
Other
general and administrative costs capitalized
(26,185
)
(30,406
)
(31,507
)
44,042
43,743
44,285
General
and administrative expense
$
54,826
$
59,262
$
65,105
____________________________________________
(1)
Labor
costs include salaries, hourly wages, bonuses, severance, and burden.
General and administrative expense was $55 million in 2013 compared to $59 million and $65 million in 2012 and 2011, respectively. For the year ended December 31, 2013, labor costs include $14 million ($11 million net of capitalized amounts) in employee-related asset divestiture costs and stock-based compensation costs include $5 million ($2 million net of capitalized amounts)
in accelerated stock-based compensation costs. These costs are associated with the divestitures of our South Texas and Texas Panhandle oil and natural gas properties during the first and fourth quarters of 2013, respectively. For the year ended December 31, 2012, stock-based compensation costs include $5 million ($4 million net of capitalized amounts) in accelerated stock-based compensation costs and labor costs include $2 million ($2 million net of capitalized amounts) in severance costs, both of which are related to the termination of our former chief executive officer. Aside from the increased employee-related asset divestiture costs in 2013, labor and stock-based compensation costs decreased,
as compared to 2012, due to reduced headcount and a decrease in the Company’s stock price. Other general and administrative cost decreases for the year ended December 31, 2013 compared to the year ended December 31, 2012 include approximately (i) $3 million less expense for split dollar life insurance, primarily due to an increase in the cash surrender value, (ii) $2 million less in professional services expense, primarily related to legal advisory and drilling consultant fees, and (iii) $2 million less in software expense. Other general and administrative costs for the year ended December 31, 2012 compared
to the year ended December 31, 2011 reflect approximately (i) $9 million less expense for attorneys’ fees and (ii) $2 million more in professional services expense. For the year ended December 31, 2011, $12 million in stock-based compensation costs ($7 million net of capitalized amounts) were recognized related to the spin-off of Lone Pine, which caused the forfeiture restrictions to lapse on a portion of each outstanding restricted stock award, thus requiring the immediate recognition of compensation cost. The percentage of general and administrative costs capitalized remained consistent between the three years presented, ranging between 38%
and 42%.
35
Depreciation, Depletion, and Amortization
The following table summarizes depreciation, depletion, and amortization expense from continuing operations for the periods indicated.
Depreciation,
depletion, and amortization expense (“DD&A”) was $172 million, or $2.27 per Mcfe, in 2013, $280 million, or $2.32 per Mcfe, in 2012, and $220 million, or $1.80 per Mcfe, in 2011. The decrease in DD&A from 2012 to 2013 was due primarily to oil and natural gas property divestitures, partially offset by oil reserve additions, which typically have higher per-unit development costs than natural gas reserves. The increase in DD&A from 2011 to 2012 was due primarily to the increase in oil reserve additions. In addition, in 2012, a significant portion of our proved undeveloped natural gas reserves,
which have lower associated development costs than proved undeveloped oil reserves, were reclassified from proved to probable status in conjunction with the decrease in the natural gas prices used to determine our proved reserves.
Ceiling Test Write-Down of Oil and Natural Gas Properties
At December 31, 2013, we recorded a ceiling test write-down of our United States cost center totaling $58 million, pursuant to the ceiling test limitation prescribed by the SEC for companies using the full cost method of accounting. This ceiling test write-down was primarily a result of the Panhandle
divestiture in the fourth quarter of 2013. Given the magnitude of the Panhandle oil and natural gas reserves as a percentage of our total reserves, the divestiture resulted in a $193 million net gain on disposition of assets rather than 100% of the divestiture proceeds reducing capitalized costs, as has typically been done with previous sales of oil and natural gas properties. This smaller reduction of capitalized costs and the loss of future net revenues from the divested proved oil and natural gas reserves were the primary factors causing the ceiling test write-down. Additional write-downs of our oil and natural gas properties may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenues from estimated production of proved oil and natural gas reserves declines
compared to prices used as of December 31, 2013, unproved properties are impaired, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any, attributable to the cost center. See “Critical Accounting Policies, Estimates, Judgments and Assumptions—Full Cost Method of Accounting” for more information regarding ceiling test write-downs.
In 2012, we recorded ceiling test write-downs of our United States cost center totaling $958 million and our Italian cost center totaling $35 million. The United
States write-downs were primarily a result of the decline in the twelve-month arithmetic average prices of natural gas and NGLs that were used to calculate the present value of future net revenues from our estimated proved oil and natural gas reserves throughout 2012. The Italian write-down resulted from our conclusion that our Italian natural gas reserves could no longer be classified as proved reserves, due to an Italian regional regulatory body’s 2012 denial of 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.
36
Impairment
of Properties
During the third quarter of 2012, we recorded a $67 million impairment of our unproved properties in South Africa based on several unsuccessful attempts to sell the properties for an amount that would allow us to recover the carrying amount of our investment in these properties. Because we had no proved reserves in South Africa, the impairment was reported as a period expense rather than being added to the costs to be amortized, and is included in the Consolidated Statement of Operations within the “Impairment of properties” line item. In December 2012, we entered into agreements to sell our South African subsidiaries and to abandon a certain exploration right in South Africa in connection with the sale of the exploration
right. The abandonment of the exploration right, which was contingent upon approval by the government of South Africa, among other things, was completed in December 2013, and we received $9 million, which is included in the Consolidated Statement of Operations within the “Other, net” line item for the year ended December 31, 2013. We are currently awaiting approval of the other sale by the government of South Africa. See Note 2 to the Consolidated Financial Statements for more information regarding this planned divestiture.
In August 2012, we entered into an agreement to sell the majority of our East Texas natural gas gathering assets and the transaction closed in October 2012. During the third quarter of 2012, these assets were
written down to their estimated fair value less cost to sell, with a $13 million impairment charge included in the Consolidated Statement of Operations within the “Impairment of properties” line item. See Note 2 to the Consolidated Financial Statements for more information regarding this divestiture.
Interest Expense
The following table summarizes interest expense from continuing operations for the periods indicated.
Interest
expense amounts include interest on the principal or borrowings outstanding, amortization of debt issuance costs, amortization of discounts and premiums, amortization of a deferred gain on a terminated interest rate swap, and credit facility commitment, letter of credit, and other fees, all as applicable.
Interest expense in 2013 totaled $120 million compared to $142 million in 2012. The $22 million decrease in interest expense was comprised of: (i) $47 million attributable to the redemption of $300 million of 8½% senior notes in October 2012 and the redemption of the remaining $300
million of 8½% senior notes in March 2013, (ii) $5 million due to the redemption of $700 million in aggregate of 7¼% senior notes and 7½% senior notes in November 2013, and (iii) $3 million attributable to the credit facility due to average outstanding borrowings under the credit facility and the commitment amount, upon which commitment fees are based, being lower in 2013 as compared to 2012. These decreases were partially offset by the following increases: (i) $27 million due to there being a full year of interest costs on the 7½% senior notes, which were issued in September 2012, and (ii) $5 million of lower capitalized interest in 2013. Interest expense totaled $142 million in 2012 compared to $150 million in 2011.
The $8 million decrease in interest expense was comprised of: (i) $20 million attributable to the redemption of $285 million of 8% senior notes in December 2011 and (ii) $6 million due to the redemption of $300 million of 8½% senior notes
37
in October 2012. These decreases were partially offset by the following increases: (i) $11 million in interest costs on the $500 million of 7½% senior notes issued in September 2012, (ii) $4 million attributable to the credit facility, primarily due to increased borrowings outstanding under the credit facility in 2012 as compared to 2011, and (iii) $3 million of lower capitalized interest in 2012. Interest
costs capitalized relate to our investments in significant unproved acreage positions that are under development. In 2013 and 2012, other interest expense consists primarily of interest accrued on the previously disclosed arbitration award in the proceeding styled Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al.. See Part I, Item 3 “Legal Proceedings” and Note 11 for more information regarding this matter.
Realized and Unrealized Gains and Losses on Derivative Instruments
The table below sets forth realized and unrealized gains and losses on derivatives from continuing operations, which are recognized under
“Costs, expenses, and other” in our Consolidated Statements of Operations for the periods indicated. Realized gains and losses represent cash settlements on derivative instruments and unrealized gains and losses represent changes in the fair value of derivative instruments. See Note 8 and Note 9 to the Consolidated Financial Statements for more information on our derivative instruments.
Our effective income tax rates were (1)%, (16)%, and 48% for the years ended December 31,
2013, 2012, and 2011, respectively. The significant differences between our blended federal and state statutory income tax rate of 36% and our effective income tax rate for all the periods shown were primarily due to changes in the valuation allowance placed against our deferred tax assets. In addition, in 2011, our effective income tax rate was impacted by a Canadian dividend tax of $29 million that was incurred on a stock dividend declared and paid by our former Canadian subsidiary, Lone Pine Resources Canada Ltd. (“LPR Canada”), to Forest, as parent, immediately before Forest’s contribution of LPR Canada to Lone Pine in conjunction with Lone Pine’s initial public offering.
The current income tax benefit in 2012 of $36 million primarily relates to
income tax refunds filed during 2012 associated with tax loss carrybacks to recover income taxes paid in 2009.
See “Critical Accounting Policies, Estimates, Judgments and Assumptions—Valuation of Deferred Tax Assets” for further discussion of our valuation allowance and Note 4 to the Consolidated Financial Statements for a reconciliation of income tax computed using the federal statutory income tax rate to income tax computed using our effective income tax rate for each period presented.
Discontinued Operations
The results of operations of Lone Pine are presented as discontinued operations
in our Consolidated Financial Statements for 2011 due to the spin-off of Lone Pine on September 30, 2011. See Note 13 to the
39
Consolidated Financial Statements for more information regarding the components of earnings from discontinued operations.
Liquidity and Capital Resources
Our
exploration, development, and acquisition activities require us to make significant operating and 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 natural gas liquids directly impact our level of cash flow generated from operations. Natural gas accounted for approximately 62% of our total production in 2013 and, as a result, our operations and cash flow are more sensitive to fluctuations
in the market price for natural gas than to fluctuations in the market prices for oil and natural gas liquids. We employ a commodity hedging strategy as an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of February 19, 2014, we had hedged, via commodity swaps and collars, approximately 33 Bcfe of our total projected 2014 production and approximately 9 Bcf of our total projected 2015 production, excluding outstanding 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. See Part I, Item 1A “Risk Factors—Our use of hedging transactions
could reduce our cash flow and/or result in reported losses,” for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions. As of February 19, 2014, all but one of our derivative instrument counterparties are lenders, or affiliates of lenders, under our credit facility. See Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk,” below for more information on our derivative contracts.
As noted above, the other primary source of liquidity is our credit facility, which had a borrowing base of $400 million
as of December 31, 2013. 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. See “Bank Credit Facility” below for further details. We had no borrowings outstanding under our credit facility as of December 31, 2013 and February 19, 2014. As noted below under “Bank Credit Facility,” our credit facility contains a covenant that we will not permit our ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding
four consecutive fiscal quarter period then most recently ended to be greater than specified levels. Depending on our overall level of indebtedness, this covenant may limit our ability to borrow funds as needed under our credit facility. See Part I, Item 1A “Risk Factors—Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities,” for the risks associated with the restrictive covenants in our debt agreements, including the credit agreement.
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. For example, we completed a private offering of $500 million of 7½% senior notes due 2020 in September 2012, using some of the proceeds to redeem $300 million of 8½% senior notes due 2014. 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. See Note 3 and Note 5 to the Consolidated Financial Statements for more information regarding our debt and equity, respectively.
We also have engaged in asset
dispositions as a means of generating additional cash to fund more attractive capital projects and to enhance our financial flexibility. For example, in November 2012, we sold all of our oil and natural gas properties located in South Louisiana for net proceeds of $211 million. Additionally, in February 2013
40
we sold all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford oil properties, for net proceeds of $321 million, which we used in March 2013 to redeem the remaining $300 million in principal amount of 8½% senior notes due 2014. In November 2013, we sold
all of our oil and natural gas properties located in the Texas Panhandle for net proceeds to-date of $965 million, which we used in November 2013 to redeem $700 million aggregate principal amount of 7¼% senior notes due 2019 and 7½% senior notes due 2020, and to pay off the outstanding balance on our credit facility. In addition, we have entered into an agreement with a third-party pursuant to which the third-party is funding a portion of the drilling and other development costs relating to certain Eagle Ford acreage in exchange for a 50% working interest in that acreage.
We believe that our existing cash, expected cash flows provided by operating activities, and the funds available under our credit facility or alternative sources of debt financing will be sufficient to fund our normal
recurring operating needs and our contractual obligations. As noted below under “Bank Credit Facility,” we have initiated discussions with the administrative agent of our credit facility to obtain an amendment to temporarily increase the maximum ratio of total debt to EBITDA allowed under the credit facility. If we are unable to obtain an amendment, the Credit Facility could be terminated. However, we believe we can arrange for alternative sources of debt financing, including securing liens against our properties or selling additional properties, sufficient to meet our recurring operating needs and contractual obligations for a reasonable period of time. Additionally, if necessary, we have the ability to slow or cease the occurrence of certain capital and operational expenditures, including those related to initiating new drilling programs, to preserve our available cash until these other sources of funding become
available at prudent terms. Any such reduction in expenditures would have a negative impact on our expected revenues, production and, potentially our reserves.
See “Going Concern Subsequent Event” below for updated disclosure on the status of our compliance with the total debt to EBITDA covenant in the Credit Facility and its effect on our ability to continue as a going concern.
Bank Credit Facility
On June 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of banks
led by JPMorgan Chase Bank, N.A. (the “Administrative Agent”) consisting of a $1.5 billion credit facility maturing in June 2016. The size of the Credit Facility may be increased by $300 million, to a total of $1.8 billion, upon agreement between us and the applicable lenders. On September 12, 2013, we entered into the First Amendment to the Credit Facility (the “First Amendment”), which was effective as of that date. The First Amendment amended, among other things, the permitted ratio of total debt to EBITDA and the definition of total debt used in the ratio calculation, and reduced the borrowing base, which governs our availability under the Credit Facility, to $700 million.
The
determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil and natural gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. A reduction of the borrowing base could require us to repay indebtedness in excess of the borrowing base in order to cover the deficiency. The next scheduled semi-annual redetermination of the borrowing base will occur on or about May 1, 2014. In addition to the scheduled semi-annual redeterminations, we and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined.
The
borrowing base is also subject to automatic adjustments if certain events occur, such as if we or any of our Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that we or any of our Restricted Subsidiaries may issue to refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if we or any of our Restricted Subsidiaries sell oil
and natural gas properties having a fair market value, including any economic loss of unwinding any related hedging agreement, in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount either (i) equal to the percentage of the
41
borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by us and the required lenders. The sale of our South Texas properties resulted in a $170 million reduction to the borrowing base when the transaction closed in February
2013 and the sale of our Panhandle properties resulted in a $300 million reduction to the borrowing base when the transaction closed in November 2013. See Note 2 to the Consolidated Financial Statements for more information regarding these divestitures. As of December 31, 2013, the borrowing base under the Credit Facility was $400 million.
The Credit Facility is collateralized by our assets. Under the Credit Facility, we are required to mortgage and grant a security interest in 75% of the present value of our estimated proved oil and natural gas properties and related assets. If our corporate credit ratings issued by Moody’s and Standard &
Poor’s meet pre-established levels, the security requirements would cease to apply and, at our request, the banks would release their liens and security interest on our properties.
Borrowings under the Credit Facility bear interest at one of two rates as may be elected by us. Borrowings bear interest at:
(i)
the greatest of (a) the prime rate announced by JPMorgan Chase Bank, N.A., (b) the federal funds effective rate from time to time plus ½ of 1%, and (c) the one-month rate applicable to dollar deposits in the London interbank market for one, two, three or six months (as selected by us) (the “LIBO Rate”) plus 1%,
plus, in the case of each of clauses (a), (b), and (c), 50 to 150 basis points depending on borrowing base utilization; or
(ii)
the LIBO Rate as adjusted for statutory reserve requirements (the “Adjusted LIBO Rate”), plus 150 to 250 basis points, depending on borrowing base utilization.
The Credit Facility includes terms and covenants that place limitations on certain types of activities, including
restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant. The First Amendment to the Credit Facility provides that we will not permit the ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended (i) for any time on or before September 11, 2013, to be greater than 4.50 to 1.00, (ii) for any time after September 11, 2013 and on or before March 31, 2014 to be greater than 5.00 to 1.00, (iii) for any time after
April 1, 2014 and on or before June 30, 2014 to be greater than 4.75 to 1.00, and (iv) for any time after June 30, 2014, to be greater than 4.50 to 1.00. The First Amendment also amends the definition of total debt such that, during any period of four fiscal quarters that includes the calendar quarter in which the Panhandle divestiture closed, any cash proceeds from the Panhandle divestiture that are reported on our consolidated balance sheet on such date are subtracted from total debt. Depending on our overall level of indebtedness, this covenant may limit our ability to borrow funds as needed under the Credit Facility. Our ratio of total
debt to EBITDA for the four consecutive fiscal quarter period ended December 31, 2013, as calculated in accordance with the Credit Facility, was 4.3. Based on our current projections, we expect the ratio of total debt to EBITDA to exceed the maximum allowed sometime during the second or third quarter of 2014 if we do not obtain an additional amendment to the Credit Facility. We have initiated discussions to that effect with the administrative agent of the Credit Facility and, with no amounts currently drawn against the facility, believe that we will be able to obtain such an amendment prior to the ratio exceeding the maximum amount currently allowed. If we fail to obtain an amendment, the Credit Facility could be terminated. However, we believe we can obtain alternative sources of debt financing sufficient for our needs, including
securing liens against our properties or selling additional properties. Additionally, if necessary, we have the ability to slow or cease the occurrence of certain capital and operational expenditures, including those related to initiating new drilling programs, to preserve our available cash until these other sources of funding become available at prudent terms.
Under certain conditions, amounts outstanding under the Credit Facility may be accelerated with the resultant termination of the facility. 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. In addition, certain events of default under the Credit Facility will result in acceleration of the indebtedness under the
Credit Facility,
42
and termination of the 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, and a failure of the liens securing the Credit Facility.
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.
At December 31, 2013 and February 19,
2014, there were no outstanding borrowings under the Credit Facility and we had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $398 million.
Credit Ratings
Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s Investors Service and Standard & Poor’s Ratings Services currently rate each series of our senior notes and, in addition, they have assigned Forest a general credit rating. Our Credit Facility includes provisions that are linked to our credit
ratings. For example, our collateral requirements will vary based on our credit ratings; however, we do not have any credit rating triggers that would accelerate the maturity of amounts due under the Credit Facility or the debt issued under the indentures for our senior notes. The indentures for our senior notes also include terms linked to our credit ratings. These terms allow us greater flexibility if our credit ratings improve to investment grade and other tests have been satisfied, in which event we would not be obligated to comply with certain restrictive covenants included in the indentures. Our ability to raise funds and the costs of any financing activities will be affected by our credit ratings at the
time any such financing activities are conducted.
Going Concern Subsequent Event
The financial statements included in this Form 10-K/A have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. We previously disclosed in our unreviewed Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, that by year end 2014 the ratio of our total debt to EBITDA may exceed the maximum allowed under
our Credit Facility unless we undertake certain mitigating actions. Absent such actions, a resultant breach of the financial covenant could cause a default under the Credit Facility, potentially resulting in an acceleration of all amounts outstanding under the Credit Facility as well as our senior unsecured notes due 2019 and 2020. As of September 30, 2014, we had approximately $13 million outstanding under the Credit Facility and $800 million in principal amount outstanding under the notes. The immediate acceleration of debt maturities of this magnitude likely would result in our bankruptcy or other restructuring.
On May 5, 2014, we entered into an Agreement and Plan
of Merger with Sabine Oil & Gas LLC (“Sabine”), under which Forest and Sabine are expected to combine their businesses in an all-stock transaction. This agreement was amended on July 9, 2014 primarily to change the structure of the transaction. If the transaction is completed, the Credit Facility will be terminated before any breach of the financial covenant occurs. Accordingly, we have elected to defer seeking an amendment or waiver rather than incurring the expense of doing so at the present time solely to avoid a “going concern” audit opinion. If, prior to year end, it appears the combination transaction will not be completed, we will again evaluate the likelihood of a breach of the financial covenant and, based on that evaluation, attempt to undertake mitigating actions with respect to the Credit Facility that we feel are most appropriate. However, there can be no assurance that any particular
actions will be available to us, or that even
43
if available, we will be able to complete them. If the combination transaction is not completed, failure to take appropriate mitigating actions in the event we are in breach of the covenant may have severely negative effects on our financial condition including, potentially, bankruptcy.
We obtained amendments to the Credit Facility as recently as September 2013 and March 2014 in order to avoid breaching the debt to EBITDA covenant. We believe that we could seek, and the lenders under our Credit Facility would provide, another amendment, or a waiver, of the covenant. Failing an amendment or waiver, we believe we could sell assets to avoid
breaching the financial covenant. Alternatively, we could obtain a new credit facility or other sources of financing. We may yet undertake some or all of these actions prior to year end, if necessary, though there is no assurance we could complete any such actions as each involves factors that are outside our control. However, inasmuch as we have not obtained a waiver or amendment to the Credit Facility, or pursued any of the other alternatives, there presently exists substantial doubt as to our ability to continue as a going concern through December 31, 2014.
Historical Cash Flow
Net cash provided by operating activities of continuing operations, net cash provided (used) by
investing activities of continuing operations, and net cash (used) provided by financing activities of continuing operations for the years ended December 31, 2013, 2012, and 2011 were as follows:
Net cash provided by operating activities of continuing operations
$
201,759
$
371,655
$
398,097
Net cash provided
(used) by investing activities of continuing operations
981,628
(467,782
)
(759,730
)
Net cash (used) provided by financing activities of continuing operations
(1,118,251
)
94,171
(173,305
)
Net
cash provided by operating activities is primarily affected by sales volumes and commodity prices net of the effects of cash settlements of our derivative contracts and changes in working capital. The decrease in net cash provided by operating activities of $170 million in 2013 as compared to 2012 was primarily due to a $164 million decrease in revenue and a decrease in cash settlements on commodity derivatives of $86 million, partially offset by a $53 million decrease in production expense and a $13 million decrease
in investment in working capital. The decrease in net cash provided by operating activities of continuing operations of $26 million in 2012 as compared to 2011 was primarily due to a $98 million decrease in revenue that was partially offset by an increase in cash settlements on commodity derivatives of $63 million.
The components of net cash provided (used) by investing activities of continuing operations for the years ended December 31, 2013, 2012, and 2011
were as follows:
Exploration, development, and leasehold acquisition costs(1)
$
(363,971
)
$
(721,536
)
$
(873,877
)
Proceeds
from sales of assets
1,347,116
262,882
121,115
Other fixed asset costs
(1,517
)
(9,128
)
(6,968
)
Net
cash provided (used) by investing activities of continuing operations
$
981,628
$
(467,782
)
$
(759,730
)
____________________________________________
(1)
Cash
paid for exploration, development, and leasehold acquisition costs as reflected in the 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 the value of common stock issued for oil and natural gas property acquisitions and capitalized stock-based compensation costs.
44
Net cash provided (used) by investing activities is primarily comprised of expenditures for the 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 $1.4 billion increase in cash provided by investing activities between 2013 and 2012 was primarily due to proceeds received from the divestiture of oil and natural gas properties, consisting principally of the South Texas divestiture in February 2013 for $321 million, the Permian Basin divestiture in September 2013 for $31 million, and the Panhandle divestiture in November 2013 for $965 million. Proceeds received from the divestiture of oil and natural gas properties in 2012 included $208 million
for the South Louisiana divestiture in November 2012. In addition, cash used for the exploration, development, and leasehold acquisition of oil and gas properties decreased $358 million from 2012 to 2013. The $292 million decrease in cash used for investing activities of continuing operations between 2012 and 2011 was primarily due to a decrease in leasehold acquisition costs and an increase in proceeds from sales of assets in 2012 as compared to 2011.
Net cash used by financing activities of $1.1
billion in 2013 primarily consisted of $1.0 billion used for the redemption of the 8½% senior notes due 2014, the partial redemption of the 7¼% senior notes due 2019 and 7½% senior notes due 2020, and net credit facility repayments of $65 million. Net cash provided by financing activities of $94 million in 2012 primarily included the issuance of the 7½% senior notes due 2020 for net proceeds of $491 million, partially offset by the partial redemption of the 8½% senior notes due 2014 for $331 million, net credit facility repayments of $40 million, and a decrease in bank overdrafts
of $24 million. Net cash used by financing activities of continuing operations of $173 million in 2011 primarily included the redemption of the 8% senior notes due 2011 for $285 million, partially offset by net credit facility borrowings of $105 million.
Capital Expenditures
Expenditures of continuing operations for property exploration, development, and leasehold acquisitions were as follows:
Unproved properties including leasehold acquisition costs
7,117
64,057
204,537
7,117
64,057
204,537
Exploration:
Direct
costs
111,290
250,302
272,422
Overhead capitalized
18,656
19,157
20,964
129,946
269,459
293,386
Development:
Direct
costs
197,790
380,496
392,406
Overhead capitalized
15,337
18,627
25,429
213,127
399,123
417,835
Total
capital expenditures(1)
$
350,190
$
732,639
$
915,758
____________________________________________
(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 $9 million, $6 million, and $3 million recorded during the years ended December 31, 2013, 2012, and 2011, respectively.
45
We have established a drilling and completion capital budget of $260 million to $270 million (excluding property acquisitions, capitalized overhead, and changes in asset retirement obligations) for 2014, which will be allocated approximately 64% to Ark-La-Tex and 36% to Eagle Ford. Primary factors impacting the level of our capital expenditures include oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions. In addition, capital expenditures will depend on availability under our Credit Facility or an alternative source of funding. If such funding is unavailable to us, or not available on prudent terms, our expected capital expenditures
would be reduced significantly. Such a reduction would have a correspondingly negative impact on our expected production, revenues, and potentially on our reserves. See “Bank Credit Facility” above for a more complete discussion of our ability to borrow under, and need to amend, the Credit Facility.
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2013:
2014
2015
2016
2017
2018
After
2018
Total
(In Thousands)
Bank debt(1)
$
1,429
$
1,429
$
714
$
—
$
—
$
—
$
3,572
Senior
notes(2)
58,555
58,555
58,555
58,555
58,555
847,659
1,140,434
Derivative
liabilities(3)
4,542
—
—
—
—
—
4,542
Other
liabilities(4)
7,838
13,736
5,708
5,300
5,258
34,461
72,301
Operating
leases(5)
22,655
15,823
15,190
8,174
2,083
7,873
71,798
Unconditional
purchase obligations(6)
6,442
5,805
5,700
—
—
—
17,947
Total
contractual obligations
$
101,461
$
95,348
$
85,867
$
72,029
$
65,896
$
889,993
$
1,310,594
____________________________________________
(1)
Bank
debt consists of commitment and letter of credit fees under our credit facility, based on the $400 million borrowing base, $2 million in outstanding letters of credit, and the fee rates in effect, all as of December 31, 2013, and assuming no changes through the remaining term of the credit facility. There were no borrowings outstanding under the credit facility as of December 31, 2013.
(2)
Senior notes consist of the principal obligations and the anticipated interest
payments thereon, based on the outstanding senior notes balances as of December 31, 2013, assuming such balances remain outstanding in full until their respective maturities.
(3)
Derivative liabilities represent the fair value of our derivative liabilities as of December 31, 2013. The ultimate settlement amounts of our derivative liabilities are unknown, because they are subject to continuing market risk. See “Critical Accounting Policies, Estimates, Judgments, and Assumptions” below for a more detailed discussion of the nature of the accounting
estimates involved in valuing derivative instruments.
(4)
Other liabilities are comprised of pension and other postretirement benefit obligations and asset retirement obligations, for which neither the ultimate settlement amounts nor the timing of settlement can be precisely determined in advance. See “Critical Accounting Policies, Estimates, Judgments, and Assumptions” below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(5)
Operating
leases consist of leases for drilling rigs, compressors, and office facilities and equipment. In January 2014, we terminated certain drilling rig operating leases for a net loss of approximately $5 million, which will reduce the operating lease obligations shown in the table above by $12 million in 2014, $11 million in 2015, $11 million in 2016, and $6 million in 2017.
(6)
Unconditional purchase obligations consist primarily of drilling commitments, throughput obligations, and voice and data services.
We
also make delay rental payments to lessors during the primary terms of oil and gas leases to delay drilling or production of wells, usually for one year. Although we are not obligated to make such payments, discontinuing them would result in the loss of the oil and gas lease. Our estimated maximum commitment of future delay lease rental payments, through 2021, totaled approximately $2 million as of December 31, 2013.
Off-balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements and other transactions that can give rise to off-balance sheet obligations.
As of December 31, 2013, the off-balance sheet arrangements and other transactions that we have entered into include (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling commitments, and (iv) other contractual obligations for which we have recorded estimated liabilities on the balance
46
sheet, but the ultimate settlement amounts are not fixed and determinable, such as derivative contracts, pension and other postretirement benefit obligations, and asset retirement obligations. We do not believe that any of these arrangements
are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.
Surety Bonds
In the ordinary course of our business and operations, we are required to post surety bonds from time to time with third parties, including governmental agencies. In addition, while we appeal the arbitration award in Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al. (see Item 3 “Legal Proceedings”), we are required to post a supersedeas bond. As of February 19, 2014, we had obtained this supersedeas bond as well as surety bonds from a number of insurance and bonding institutions covering certain
of our current and former operations in the United States in the aggregate amount of approximately $36 million. See Part I, Item 1 “Business—Industry Regulation” for further information.
Critical Accounting Policies, Estimates, Judgments, and Assumptions
Full Cost Method of Accounting
The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the full cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported
in financial statements. We have elected to follow the full cost method, which is described below.
Under the full cost method, separate cost centers are maintained for each country in which we incur costs. 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) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded.
Capitalized costs applicable to each full cost center are depleted using the units of production method based on conversion to common units of measure
using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for in the current quarter and prospectively in the depletion calculations. We update our quarterly depletion calculations with our quarter-end reserves estimates. See Part I, Item 1, “Business—Reserves” and Note 14 to the Consolidated Financial Statements for a more complete discussion of our estimated proved reserves as of December 31, 2013.
Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter for each cost center. The full cost 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 test determines a limit, or ceiling, on the book value of oil and natural gas properties. That limit is basically the after tax present value of the future net cash flows from estimated proved oil and natural gas reserves calculated using current prices, which are the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, and NGL prices. This ceiling is compared to the net book value of the oil and natural gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, a non-cash write-down is required. In 2013, we recorded a ceiling test write-down in our United States cost center totaling $58 million that resulted primarily from the Panhandle divestiture in the fourth quarter of
2013. Given the magnitude of the Panhandle oil and natural gas reserves as a percentage of our total reserves, the divestiture resulted in a $193 million net gain on disposition of assets rather than 100% of the divestiture proceeds reducing capitalized costs, as has typically been done with previous sales of oil and natural gas properties. This smaller reduction of capitalized costs and the loss of future net revenues from the divested proved oil and natural gas reserves were the primary factors causing the ceiling test write-down. In 2012, we recorded ceiling test write-downs in our United States cost center totaling $958 million and in our Italian cost center totaling $35 million. The United States ceiling test write-
47
downs in 2012 were primarily a result of the decline in the twelve-month arithmetic average prices of natural gas and NGLs.
In areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering factors such as the primary lease terms of the properties, the holding period of
the properties, geographic and geologic data obtained relating to the properties, and estimated discounted future net cash flows from the properties. Where it is not practicable to individually assess properties whose 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 in the appropriate full cost pool, or reported as impairment expense in the Consolidated Statements of Operations, as applicable. During the year ended December 31, 2012, we recorded a $67 million impairment of our unproved properties in South Africa based on several unsuccessful attempts to sell the properties for an amount that would allow us to recover the carrying amount of our investment in these properties. Because we had no proved
reserves in South Africa, and therefore no costs being amortized, the impairment was reported as a period expense and was included in the Consolidated Statement of Operations within the “Impairment of properties” line item.
Under the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments are also assessed on a property-by-property basis and are charged to expense when assessed.
The full cost method is used to account for our oil and gas exploration and development activities because we believe it appropriately reports the costs of our exploration programs as part of an overall
investment in discovering and developing proved reserves.
Goodwill
Goodwill is tested for impairment on an annual basis in the second quarter of the year. In addition, we test goodwill for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.
In the first step of testing for goodwill impairment, we estimate the fair value of our reporting unit, which we have determined to be our U.S. geographic operating segment, and compare the fair value with the carrying value of the net assets assigned to the reporting unit. If the fair value is greater than the carrying value, then no impairment
results. If the fair value is less than the carrying value, then we perform a second step and determine the fair value of the goodwill. If the reporting unit has a negative carrying value, we perform the second step if it is more likely than not that a goodwill impairment exists. In this second step, the fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of the reporting unit as a whole, as if that reporting unit had just been acquired and the purchase price was being initially allocated. If the fair value of the goodwill is less than its carrying value for a reporting unit, an impairment charge would be recorded to earnings in the Consolidated Statement of Operations.
To determine the fair value of our reporting unit, we calculate the market capitalization of our reporting unit based
on our quoted stock price. Quoted prices in active markets are the best evidence of fair value. However, because value results from the ability to take advantage of synergies and other benefits that exist from a collection of assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity securities may not be representative of the fair value of the reporting unit as a whole. Accordingly, we add a control premium to the market capitalization to determine the total fair value of our reporting unit. Additionally, we subtract an estimated amount that market participants would attribute to our stock price for the value of our international operations, to which no goodwill has been allocated. The sum of our market capitalization
48
and
control premium, less the international value, is the fair value of our reporting unit. This amount is then compared to the carrying value of our reporting unit. In performing step two of the goodwill impairment test, one of the more significant estimates is determining the fair value of our oil and natural gas properties. To determine the fair value of our oil and natural gas properties, we consider relevant information in market transactions that involve comparable assets.
At the time of our annual 2013 goodwill impairment test, our reporting unit had a negative carrying value. Because of the presence of adverse qualitative factors, including limitations on accessing capital and a sustained decreased share price, we performed the second step of the impairment test. This test did not result in an impairment. Because the Panhandle
divestiture represented more than 25% of our total proved reserves at the time the divestiture closed and, therefore, a gain or loss on divestiture was required to be recorded, we allocated $105 million of goodwill to the Panhandle divestiture in determining the gain on the divestiture. Subsequent to the divestiture, as of December 31, 2013, we performed an interim impairment test on the remaining goodwill balance. At the time of that test, the carrying value of our reporting unit was greater than zero and was exceeded by the fair value of the reporting unit by 835%; therefore, goodwill of the reporting unit was considered not impaired and the second step of the impairment test was unnecessary.
As described above, the key assumptions
used in our goodwill impairment test are our stock price, number of shares outstanding, a control premium, and value attributable to our international operations. There is no uncertainty as to what the stock price is as of the date of the test, since it is directly observable, or as to the number of shares outstanding. The control premium was based on marketplace data of actual control premiums in the oil and natural gas extraction industry. The value attributed to our international operations is minimal and is based on a contracted sales price with a third-party that has been previously disclosed. We note that the fair value of our reporting unit based solely on our stock price and number of shares outstanding (i.e. excluding the control premium and value attributable to our international operations) exceeded the carrying value of our reporting unit by a significant margin.
As
discussed above, our stock price and number of shares outstanding are the primary drivers of our reporting unit fair value. Therefore, downward changes in the stock price would negatively affect the fair value of our reporting unit. However, since the carrying value of our reporting unit is low (due primarily to inception-to-date full cost ceiling test write-downs), as of December 31, 2013, our stock price would have to be below one dollar before the fair value of the reporting unit may be at risk of being lower than the carrying value.
When performing the second step of the impairment test, key assumptions utilized to determine the fair value of oil and natural gas properties include recent offers received from third-parties to purchase reserves and acreage, acreage values observed
in the marketplace, and the present value of estimated future cash flows related to our reserves.
Due to the significant judgments that go into the goodwill impairment test, as discussed above, there can be no assurance that our goodwill will not be impaired at any time in the future.
Oil and Gas Reserves Estimates
Our estimates of proved reserves are based on the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The accuracy of any reserves estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as oil, natural gas, and NGL prices that we are required to use pursuant to SEC regulations change from period-to-period, the estimate of proved reserves will also change and the change can be significant. Despite the inherent uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to
49
amortize our oil and natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and natural gas properties are also subject to a ceiling test limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures included in Note 14 to the Consolidated Financial Statements.
Reference should be made to “Reserves” under Part I, Item 1 “Business,” and “Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves and our financial condition,” under Part I, Item 1A “Risk Factors,”
in this Annual Report on Form 10-K.
Fair Value of Derivative Instruments
We use the income approach in determining the fair value of our derivative instruments, utilizing present value techniques for valuing our swaps and option-pricing models for valuing our collars, swaptions, and puts. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. The values we report in our financial statements change as these estimates are revised to reflect changes in market conditions or other factors, many of which are beyond our control.
The accounting treatment for the changes
in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of operations, because changes in fair value of the derivative offset changes in the fair value of the hedged item. Where hedge accounting is not elected, or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings as other income or expense. We have elected not to use hedge accounting to account for our derivative instruments
and, as a result, all changes in the fair values of our derivative instruments are recognized in earnings as unrealized gains or losses in the line item “Realized and unrealized losses (gains) on derivative instruments, net” in our Consolidated Statements of Operations. Also included in this line item are the cash settlements, or realized gains and losses, on our derivative instruments.
Due to the volatility of oil, natural gas, and natural gas liquids prices, the estimated fair values of our derivative instruments are subject to large fluctuations from period to period. See Item 7A “Quantitative and Qualitative Disclosures about Market Risk” for a sensitivity analysis of the change in net fair value of our commodity derivatives based on a hypothetical change in commodity prices.
Valuation
of Deferred Tax Assets
We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined based on differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect of a change in tax rates on income tax assets and liabilities is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.
In assessing the need for a valuation allowance
on our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. In making this assessment, we consider 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
50
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 us included a three-year cumulative book loss driven primarily by the ceiling test write-downs incurred in 2012 and 2013. Positive evidence considered by us included forecasted book income in future years 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 we determined to be relevant evidence, we have recorded a valuation allowance of $504 million against our deferred tax assets as of December 31, 2013. Although we expect future book income based on future production and future NYMEX oil and natural gas prices, oil and natural gas prices have been highly volatile over recent years, and only a portion of our forecasted production is hedged through the end of 2015.
Asset
Retirement Obligations
Forest has obligations to remove tangible equipment and restore locations at the end of the oil and natural gas production operations. Estimating the future restoration and removal costs, or asset retirement obligations (“ARO”), requires us to make estimates and judgments, because most of the obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs periodically change, as do regulatory, political, environmental, safety, and public relations considerations.
Inherent in the calculation of the present value of our ARO are numerous assumptions and judgments, including
the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, which is included in “Other, net” in the Consolidated Statements of Operations.
Reconciliation of Non-GAAP Measure
Adjusted EBITDA
In addition to
reporting net earnings (loss) from continuing operations as defined under GAAP, we also present adjusted earnings from continuing operations before interest, income taxes, depreciation, depletion, amortization, and certain other items (“Adjusted EBITDA”), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings from continuing operations before interest expense, income taxes, depreciation, depletion, and amortization, as well as other items including non-cash operating items such as unrealized gains and losses on derivative instruments, which represent changes in the fair values of the derivative instruments, and accretion of asset retirement obligations, all as 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) from continuing operations (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) from continuing operations and revenues, to measure operating performance. The following table provides a reconciliation of net earnings (loss) from continuing operations, the most directly comparable GAAP measure, to Adjusted
EBITDA for the periods presented.
Unrealized
losses (gains) on derivative instruments, net
30,923
39,126
(39,087
)
Interest expense
119,829
141,831
149,755
Gain
on asset dispositions, net
(202,023
)
—
—
Loss on debt extinguishment, net
48,725
36,312
—
Accretion
of asset retirement obligations
2,982
6,663
6,082
Ceiling test write-down of oil and natural gas properties
57,636
992,404
—
Impairment
of properties
—
79,529
—
Depreciation, depletion, and amortization
171,557
280,458
219,684
Stock-based
compensation
8,875
15,074
20,536
Legal proceeding costs
—
29,251
6,500
Employee-related
asset disposition costs
11,178
1,851
—
Rig stacking
9,989
6,604
—
Adjusted
EBITDA from continuing operations
$
332,888
$
513,609
$
550,865
Item 7A. 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 use 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, in our credit facility. These arrangements, 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.
52
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, we
pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. The table below sets forth our outstanding commodity swaps as of December 31, 2013.
Commodity
Swaps
Natural Gas (NYMEX HH)
Oil (NYMEX WTI)
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)
Calendar 2014
70
$
4.38
$
4,728
3,500
$
95.34
$
(327
)
Calendar
2015
20
4.20
400
—
—
—
Commodity
Options
In connection with several natural gas and oil swaps entered into, we granted option instruments (several swaptions and puts) to the swap counterparties in exchange for our receiving premium hedged prices on the natural gas and oil swaps. Under the terms of the swaption agreements, the counterparties have the option to enter into future swaps with us. The swaptions may not be exercised until their expiration dates. Under the terms of the put agreements, the counterparties have the option to put specified quantities of oil to us at specified prices. The puts may be exercised monthly by the counterparties. The table below sets forth the outstanding commodity options as of December 31, 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 2016
December
2014
10
$
4.18
$
(810
)
—
$
—
$
—
Oil
Swaptions:
Calendar 2015
December
2014
—
—
—
3,000
100.00
(1,447
)
Calendar
2015
December 2014
—
—
—
1,000
106.00
(219
)
Calendar
2015
December 2014
—
—
—
1,000
99.75
(495
)
Calendar
2015
December 2014
—
—
—
1,000
99.00
(543
)
Oil
Put Options:
Monthly
Calendar 2014
Monthly Calendar 2014
—
—
—
2,000
70.00
(237
)
The
estimated fair value at December 31, 2013 of all our commodity derivative instruments based on various inputs, including published forward prices, was a net asset of approximately $1 million.
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. For example, a hypothetical 10% increase in the forward oil and natural gas prices used to calculate the fair values of our commodity derivative instruments at December 31, 2013 would decrease the net fair value of our commodity derivative
instruments at December 31, 2013 by approximately $32 million to a net liability of $31 million. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Actual gains or losses recognized
53
related to our commodity derivative instruments will likely differ from those estimated at December 31, 2013 and will depend exclusively on the price of the commodities on the specified settlement
dates provided by the derivative contracts.
Represents
the hedged floor and ceiling price per MMBtu.
Derivative Fair Value Reconciliation
The table below sets forth the changes that occurred in the fair values of our derivative contracts during the year ended December 31, 2013, beginning with the fair value of our derivative contracts 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 December 31, 2013 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
The
following table presents principal amounts and related interest rates by year of maturity for our senior notes at December 31, 2013:
2019
2020
Total
Senior
notes:
Principal (in thousands)
$
577,914
$
222,087
$
800,001
Fixed
interest rate
7.25
%
7.50
%
7.32
%
Effective interest rate(1)
7.24
%
7.50
%
7.31
%
____________________________________________
(1)
The
effective interest rate on the 7.25% senior notes due 2019 differs from the fixed interest rate due to the amortization of the related premium on the notes.
54
Foreign Currency Exchange Rate 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.
55
Item 8. Financial Statements and Supplementary Data.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of Forest Oil Corporation
We
have audited the accompanying consolidated balance sheets of Forest Oil Corporation as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Forest Oil Corporation at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December
31, 2013, in conformity with U.S. generally accepted accounting principles.
The accompanying consolidated financial statements have been prepared assuming that Forest Oil Corporation will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has determined that it expects to fail a financial covenant in its Credit Facility sometime prior to the end of 2014, which could result in the acceleration of all borrowings thereunder and the Company’s senior unsecured notes due 2019 and 2020. This raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans
in regard to this matter are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Forest Oil Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 26, 2014, except for the effects of the material weaknesses described in the sixth paragraph of that report as to which the date is October 1,
2014, expressed an adverse opinion thereon.
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 (sometimes referred to as “NGLs”) primarily in the United States. 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, with its core operational areas being Eagle Ford in South Texas and Ark-La-Tex in Texas, Louisiana, and Arkansas, and has exploratory and development interests in two other countries. On June 1, 2011, Forest completed an initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which held Forest’s ownership interests
in its Canadian operations. On September 30, 2011, Forest distributed, or spun-off, its remaining 82% ownership in Lone Pine to Forest’s shareholders by means of a special stock dividend of Lone Pine shares. See Note 5 for more information regarding the initial public offering and spin-off of Lone Pine. Unless the context indicates otherwise, the terms “Forest,” the “Company,”“we,”“our,” and “us,” as used in this Annual Report on Form 10-K, refer to Forest Oil Corporation and its subsidiaries.
Basis of Presentation and Principles of Consolidation
The
consolidated financial statements include the accounts of Forest and its consolidated subsidiaries. As a result of the spin-off, Lone Pine’s results of operations are reported as discontinued operations. See Note 13 for more information regarding the results of operations of Lone Pine. All intercompany balances and transactions have been eliminated.
Subsequent Event – Going Concern and Management’s Plan
The financial statements included in this Form 10-K/A have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The accompanying financial statements
do not reflect any adjustments that might result if the Company is unable to continue as a going concern. Forest previously disclosed in its unreviewed Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, that by year end 2014 the ratio of its total debt to EBITDA may exceed the maximum allowed under its bank credit facility unless it undertakes certain mitigating actions. Absent such actions, a resultant breach of the financial covenant could cause a default under the credit facility, potentially resulting in an acceleration of all amounts outstanding under the credit facility as well as Forest’s senior unsecured notes due 2019 and 2020. As of September 30, 2014, Forest had approximately $13.0 million outstanding under the credit
facility and $800.0 million in principal amount outstanding under the notes.
The Company obtained amendments to the credit facility as recently as September 2013 and March 2014 in order to avoid breaching the debt to EBITDA covenant. Forest believes that it could seek, and the lenders under its credit facility would provide, another amendment, or a waiver, of the covenant. Failing an amendment or waiver, Forest believes it could sell assets to avoid breaching the financial covenant. Alternatively, Forest could obtain a new credit facility or other sources of financing. Forest may yet undertake some or all of these actions prior to year end, if necessary, though there is no assurance Forest could complete any such actions as each involves factors that are outside its control.
However, inasmuch as Forest has not obtained a waiver or amendment to the credit facility, or pursued any of the other alternatives, there presently exists substantial doubt as to Forest’s ability to continue as a going concern through December 31, 2014.
63
Assumptions, Judgments, and Estimates
In the course of preparing the 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 natural gas liquids 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.
Cash Equivalents
The Company considers all highly liquid investments with original maturities of three months or less and all money market funds with no restrictions on the Company’s ability to withdraw money from the funds to be cash equivalents.
Property and Equipment
The Company uses the full cost
method of accounting for oil and natural gas properties. Separate cost centers are maintained for each country in which the Company has operations. The Company’s primary oil and gas operations are conducted in the United States. Prior to the spin-off of Lone Pine on September 30, 2011, the Company also had operations in Canada. 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 years ended December 31, 2013, 2012, and 2011, Forest capitalized $34.0 million, $37.8 million, and $46.4 million, respectively, of general and administrative costs (including stock-based compensation) related to its continuing operations. Interest costs related to significant unproved properties that are under development are also capitalized to oil and natural gas properties. During the years ended December 31, 2013, 2012, and 2011,
Forest capitalized $2.0 million, $7.2 million, and $10.3 million, respectively, of interest costs attributed to the unproved properties of its continuing operations.
Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering factors such as the primary lease terms of the properties, the holding period of the properties, geographic and geologic data obtained relating to the properties, 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 estimated 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.
During the year ended December 31, 2012, Forest recorded a $66.9 million impairment of its unproved properties in South Africa based on several unsuccessful attempts to sell the properties for an amount that would allow Forest to recover the carrying
amount of its investment in these properties. Because Forest had no proved reserves in South Africa, the impairment was reported as a period expense, rather than being added to the costs to be amortized, and is included in the Consolidated Statement of Operations within the “Impairment of properties” line item.
64
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 bases 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.
At December 31, 2013, Forest recorded a ceiling test write-down of its United States cost center totaling $57.6 million, which resulted primarily from the Panhandle divestiture. Given the magnitude of the Panhandle oil and natural gas reserves as a percentage of Forest’s total reserves, the divestiture resulted in a $193.0 million net gain on disposition of assets rather than 100% of the divestiture proceeds reducing capitalized costs, as has typically been done with previous sales of oil and natural gas properties. This smaller reduction of capitalized costs and the loss of future net revenues from the divested proved
oil and natural gas reserves were the primary factors causing the ceiling test write-down. See Note 2 for more information on the Panhandle divestiture.
In 2012, Forest recorded ceiling test write-downs of its United States cost center totaling $957.6 million and its Italian cost center totaling $34.8 million. The United States write-downs resulted primarily from decreases in natural gas and NGL prices. The Italian write-down resulted from Forest concluding that its Italian natural gas reserves could no longer be classified as proved reserves, due to an Italian regional regulatory body’s 2012 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.
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. As noted above, a gain was recognized on the Panhandle divestiture in 2013. See Note 2 for more information on the Panhandle divestiture.
Depletion of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Company uses its quarter-end reserves estimates
to calculate depletion for the current quarter.
Furniture and fixtures, leasehold improvements, computer hardware and software, and other equipment are depreciated on the straight-line method over the estimated useful lives of the assets, which range from three to fifteen years.
Asset Retirement Obligations
Forest records the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each
period to its present value. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Forest’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and natural gas properties.
65
The following table summarizes the activity for the Company’s asset retirement obligations for the periods indicated:
Asset retirement obligations at beginning of period
$
58,585
$
78,938
Accretion
expense
2,982
6,663
Liabilities incurred
2,362
1,412
Liabilities settled
(2,726
)
(5,650
)
Disposition
of properties
(42,082
)
(27,418
)
Revisions of estimated liabilities
6,234
4,640
Asset retirement obligations at end of period
25,355
58,585
Less:
current asset retirement obligations
(2,726
)
(2,430
)
Long-term asset retirement obligations
$
22,629
$
56,155
Oil,
Natural Gas, and NGL Sales
The Company recognizes revenues when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the Company’s price to the buyer is fixed or determinable and (iv) collectibility is reasonably assured.
When the Company has an interest with other producers in properties from which natural gas is produced, the
Company uses the entitlements method to account for any imbalances. Imbalances occur when the Company sells more or less product than it is entitled to under its ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that the Company sells in excess of its entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount the Company sells is recognized as revenue and an asset is accrued. At December 31, 2013 and 2012, the
Company had gas imbalance liabilities of $4.3 million and $7.5 million, respectively, and gas imbalance assets of $3.4 million and $6.7 million, respectively.
In 2013, sales to two purchasers were approximately 23%, or $102.5 million, and 17%, or $73.5 million, respectively, of the Company’s
total revenues. In 2012, sales to two purchasers were approximately 19%, or $117.2 million, and 14%, or $82.1 million, respectively, of the Company’s total revenues. In 2011, sales to one purchaser were approximately 22%, or $151.9 million, of the Company’s
total revenues from continuing operations. Forest’s revenues from continuing operations are attributable to the United States. Forest believes that the loss of one or more of the Company’s current oil, natural gas, and NGL purchasers would not have a material adverse effect on the Company’s ability to sell its production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption.
66
Accounts Receivable
The
components of accounts receivable are as follows:
Forest’s accounts receivable are primarily from purchasers of the Company’s oil, natural gas, and NGL sales and from other exploration and production companies which own working interests in the properties that the
Company operates. This industry concentration could adversely impact Forest’s overall credit risk because the Company’s customers and working interest owners may be similarly affected by changes in economic and financial market conditions, commodity prices, and other conditions. Forest’s oil, natural gas, and NGL production is sold to various purchasers in accordance with the Company’s credit policies and procedures. These policies and procedures take into account, among other things, the creditworthiness of potential purchasers and concentrations of credit risk. Forest generally requires letters of credit or parental guarantees for receivables from parties that are deemed to have sub-standard credit or other financial concerns, unless the
Company can otherwise mitigate the perceived credit exposure. Forest routinely assesses the collectibility of all material receivables and accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.
Income Taxes
The Company recognizes deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred tax benefits are recorded as an asset to the extent that management assesses the utilization of such
assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax assets.
Earnings (Loss) per Share
Basic earnings (loss) per share is computed using the two-class method by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. The two-class method of computing earnings (loss) per share is required to be used since Forest has participating securities. The two-class method is an earnings allocation formula that determines earnings (loss) per share for each class of common stock and participating security according to dividends declared (or accumulated)
and participation rights in undistributed earnings. Holders of restricted stock issued under Forest’s stock incentive plans have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock. Holders of phantom stock units issued to directors under Forest’s stock incentive plans also have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock, while phantom stock units issued to employees do not participate in dividends. Stock options and cash-settled performance units issued under Forest’s stock incentive plans do not participate in dividends. Share-settled performance units issued under Forest’s stock incentive plans do not participate in dividends in their current form. Holders of these performance units participate in dividends paid during the performance units’ vesting period only after the performance units vest and common shares are
deliverable under the terms of the performance unit awards. Share-
67
settled performance units may vest with no common shares being deliverable, depending on Forest’s shareholder return over the performance units’ vesting period in relation to the shareholder returns of specified peers. See Note 6 for more information on Forest’s stock-based incentive awards. In summary, restricted stock issued to employees and directors and phantom stock units issued to directors are participating securities, and earnings are allocated to both common stock and these participating securities under the two-class method. However, these participating securities do not have a contractual obligation to share in Forest’s losses. Therefore, in periods of
net loss, none of the loss is allocated to these participating securities.
Diluted earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period, increasing the denominator to include the number of additional common shares that would have been outstanding if the dilutive potential common shares (e.g. stock options, unvested restricted stock, unvested share-settled phantom stock units, and unvested share-settled performance units) had been issued. Additionally, the numerator is also adjusted for certain contracts that provide the issuer or holder with a choice between settlement methods. Diluted earnings per share is computed using the more dilutive of the treasury stock method
or the two-class method. Under the treasury stock method, the dilutive effect of potential common shares is computed by assuming common shares are issued for these securities at the beginning of the period, with the assumed proceeds from exercise, which include average unamortized stock-based compensation costs, assumed to be used to purchase common shares at the average market price for the period, and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) included in the denominator of the diluted earnings per share computation. The number of contingently issuable shares pursuant to the outstanding share-settled performance units is included in the denominator of the computation of diluted earnings per share based on the number of shares, if any, that would be issuable if the end of the reporting period were the end of the contingency period and if the result would be dilutive. Under the two-class
method, the dilutive effect of non-participating potential common shares is determined and undistributed earnings are reallocated between common shares and participating securities. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the year ended December 31, 2012. Unvested restricted stock grants were not included in the calculations of diluted earnings per share for the years ended December 31, 2013 and 2011 as their inclusion would have an antidilutive effect.
The following reconciles net earnings (loss)
as reported in the Consolidated Statements of Operations to net earnings (loss) used for calculating basic and diluted earnings (loss) per share for the periods presented.
Less:
net earnings attributable to noncontrolling interest
—
—
—
—
—
—
—
(4,987
)
(4,987
)
Less:
net earnings attributable to participating securities
(2,099
)
—
(2,099
)
—
—
—
(2,037
)
(821
)
(2,858
)
Net
earnings (loss) attributable to common stock for basic earnings (loss) per share
71,825
—
71,825
(1,288,931
)
—
(1,288,931
)
96,223
38,761
134,984
Adjustment
for liability classified stock-based compensation awards
—
—
—
—
—
—
—
(707
)
(707
)
Net
earnings (loss) for diluted earnings (loss) per share
$
71,825
$
—
$
71,825
$
(1,288,931
)
$
—
$
(1,288,931
)
$
96,223
$
38,054
$
134,277
68
The following reconciles basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the periods presented.
Weighted average common shares outstanding during the period for basic earnings (loss) per share
116,125
114,958
111,690
Dilutive effects of potential common shares
—
—
1,178
Weighted
average common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings (loss) per share
116,125
114,958
112,868
Stock-Based Compensation
Compensation cost is measured at the grant
date based on the fair value of the awards (stock options, restricted stock, share-settled performance units, employee stock purchase plan rights) or is measured at the reporting date based on the fair value of the awards (cash-settled phantom stock units and cash-settled performance units), and is recognized on a straight-line basis over the requisite service period (usually the vesting period). Compensation cost for awards with only service conditions that have a graded vesting schedule is recognized on a straight-line basis over the requisite service period for each separately vesting portion of the award.
Derivative Instruments
The Company records all derivative instruments, other than those that meet
the normal purchases and sales exception, as either assets or liabilities at fair value. The Company has not elected to designate its derivative instruments as hedges and, therefore, records all changes in fair value of its derivative instruments as unrealized gains and losses through earnings, with such changes reported in a single line item in the Consolidated Statements of Operations together with cash settlements, or realized gains and losses, on the derivative instruments.
Debt Issue Costs
Included in other assets are costs associated with the issuance of our senior notes and our revolving bank credit facility. The remaining unamortized debt issue costs at December 31,
2013 and 2012 totaled $13.4 million and $27.0 million, respectively, and are being amortized over the life of the respective debt instruments. In connection with the early repayment of senior notes in 2013, $8.9 million of unamortized debt issue costs were written-off.
Inventory
Inventories, which are carried at average cost with adjustments made from time to time to recognize, as appropriate, any reductions in value, were comprised of $2.2 million and $4.2
million of materials and supplies as of December 31, 2013 and 2012, respectively. The Company’s materials and supplies inventory, which is acquired for use in future drilling operations, is primarily comprised of items such as tubing and casing.
Goodwill
The Company is required to perform an annual impairment test of goodwill in lieu of periodic amortization. The
Company performs its annual goodwill impairment test in the second quarter of the year. In addition, the Company tests goodwill for impairment if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The impairment test requires the Company to estimate the fair value of the reporting unit to which goodwill has been assigned and, in some cases, the fair values of the assets and liabilities assigned to the reporting unit. Although the Company bases its fair value estimates on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and uncertain. The
69
Company allocates a portion of goodwill to divestitures of more than 25% of the Company’s total proved reserves. During the year ended December 31, 2013, the Company allocated $105.0 million of goodwill to the Panhandle divestiture. See Note 2 for more information regarding this divestiture. The Company had no goodwill impairments for the years ended December 31, 2013,
2012, and 2011.
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). Items included in the Company’s other comprehensive income (loss) during the last three years are net foreign currency gains and losses related to the translation of the assets and liabilities of Lone Pine’s Canadian operations
prior to the spin-off of Lone Pine on September 30, 2011, and defined benefit postretirement plan gains and losses. See Note 7 for more information regarding Forest’s defined benefit postretirement plans.
The components of other comprehensive income (loss), both before-tax and net-of-tax, for the years ended December 31, 2013, 2012, and 2011 are as follows:
Net periodic
benefit cost components arising during the period
$
(11,058
)
$
3,979
$
(7,079
)
Actuarial losses reclassified from accumulated other comprehensive loss and included in net periodic benefit cost
641
(231
)
410
(10,417
)
3,748
(6,669
)
Foreign
currency translation losses
Foreign currency translation losses arising during the period
(27,852
)
—
(27,852
)
Amounts
reclassified from accumulated other comprehensive loss
—
—
—
(27,852
)
—
(27,852
)
Other
comprehensive loss
$
(38,269
)
$
3,748
$
(34,521
)
____________________________________________
(1)
Tax
expense of $3.6 million for the year ended December 31, 2013 is offset by an equal decrease in the valuation allowance.
70
The components of accumulated other comprehensive income (loss) attributable to Forest Oil Corporation common shareholders for the years ended December 31, 2013, 2012, and 2011 are as follows:
Furniture and fixtures, leasehold improvements, computer hardware and software, and other equipment
61,903
64,036
Accumulated depreciation and amortization
(50,058
)
(46,908
)
Net
other property and equipment
11,845
17,128
Total net property and equipment
$
818,569
$
1,754,238
____________________________________________
(1)
Includes
inception-to-date ceiling test write-downs.
71
The following table sets forth a summary as of December 31, 2013 of Forest’s unproved properties, all of which are located in the United States, by the year in which such property costs were incurred:
Total
2013
2012
2011
2010
and Prior
(In Thousands)
Acquisition costs
$
48,095
$
5,078
$
4,155
$
2,515
$
36,347
Exploration
costs
5,550
4,722
194
57
577
Total
unproved oil and natural gas properties
$
53,645
$
9,800
$
4,349
$
2,572
$
36,924
The
majority of the unproved oil and natural gas property costs, which are not subject to depletion, relate to oil and natural gas property acquisitions and leasehold acquisition costs as well as work-in-progress on various projects. The Company expects that substantially all of its unproved property costs as of December 31, 2013 will be reclassified to proved properties within ten years.
Divestitures
Texas Panhandle
In October 2013, Forest entered into an agreement to sell
all of its oil and natural gas properties located in the Texas Panhandle for $1.0 billion in cash. The purchase price was adjusted at closing on November 25, 2013 to $944.1 million in order to, among other things, reflect an economic effective date of October 1, 2013. Subsequent to closing, Forest received an additional $21.0 million for post-closing title curative work completed, for total cash proceeds received to-date of $965.1 million. As of December 31, 2013, there is $32.9 million remaining in escrow, which Forest may receive as consents-to-assign
are received and further post-closing title curative work is completed. Of the $32.9 million escrow balance, $10.0 million supports post-closing indemnities that Forest may owe to the buyer under the terms of the purchase and sale agreement. Any of the $10.0 million remaining in escrow at the one-year anniversary of the closing will be paid to Forest. Forest used a portion of the Panhandle divestiture proceeds to repay the balance outstanding on its credit facility and to redeem $700.0 million aggregate principal amount of its 7¼% senior notes due 2019 and 7½% senior notes due 2020.
In connection with the Panhandle divestiture, Forest incurred exit costs consisting of one-time employee termination
benefits and other associated costs, as shown in the following table.
Other
associated costs consist of financial advisor fees and retention bonuses paid to certain employees.
(2)
Of the $12.5 million total expected amount, $5.0 million was recognized in “General and administrative” expense and $5.8 million was recognized in “Other, net” in the Consolidated Statement of Operations for the year ended December 31, 2013. Additionally, $1.1 million was capitalized in “Oil and natural gas properties” in the Consolidated Balance
Sheet pursuant to the full cost method of accounting. The remaining $.5 million will be accrued in 2014 over the remaining retention period of the affected employees.
(3)
The December 31, 2013 estimated liability balance is included in “Accounts payable and accrued liabilities” in the Consolidated Balance Sheet, and Forest expects it will be paid during the first half of 2014.
72
Under the full cost method of accounting, sales of oil and natural gas properties are typically accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center. A significant alteration would not ordinarily be expected to occur for sales involving less than 25% of the reserve quantities of a given cost center. The proved reserves associated with the Panhandle divestiture represented more than 25% of Forest’s total proved reserves at the time the divestiture closed. Forest concluded that accounting for the divestiture as an adjustment of capitalized costs would significantly alter the relationship between capitalized costs and proved reserves.
Therefore, a gain was recognized on the divestiture. The historical net book value of Forest’s oil and natural gas properties at the time of sale was allocated between the properties divested and properties retained based on proved reserves. As discussed in Note 1—“Goodwill”, Forest allocated $105.0 million of goodwill to the Panhandle divestiture in determining the gain on the divestiture. The net gain recognized on the divestiture for the year ended December 31, 2013 was $193.0 million.
South Texas
In January 2013, Forest entered into an agreement to sell all of its oil and natural gas properties
located in South Texas, excluding its Eagle Ford oil properties, for $325.0 million in cash. This transaction closed on February 15, 2013 and was subject to customary purchase price adjustments, resulting in Forest receiving net cash proceeds of $320.9 million. Forest used the proceeds from this divestiture to redeem the remaining $300.0 million of its 8½% senior notes due 2014. In connection with the South Texas divestiture, Forest incurred one-time employee termination benefit costs of $7.5 million ($5.7 million net of capitalization), which are included in “General and administrative” expense in the Consolidated Statement of Operations and were paid in full during 2013, with no further
one-time employee termination benefit costs expected to be made for this specific divestiture.
Permian Basin
In August 2013, Forest entered into an agreement to sell a portion of its largely undeveloped acreage position located in Crockett County in the Permian Basin of West Texas. This transaction closed on September 10, 2013, and Forest received net cash proceeds of $31.4 million, after customary purchase price adjustments. Forest retained a Permian Basin acreage position located in Pecos and Reeves Counties, Texas. Forest used the proceeds from this divestiture to reduce outstanding borrowings under its credit facility.
South
Louisiana
In October 2012, Forest entered into an agreement to sell all of its oil and natural gas properties located in South Louisiana for $220.0 million in cash. This transaction closed on November 16, 2012 and was subject to customary purchase price adjustments, resulting in Forest receiving net cash proceeds of $211.3 million.
73
Gas Gathering Assets
In August
2012, the Company entered into an agreement to sell the majority of its East Texas natural gas gathering assets for $34.0 million in cash. This transaction closed on October 31, 2012, and Forest received net cash proceeds of $28.8 million, after customary purchase price adjustments. At the time of closing, there were up to $9.0 million of additional performance payments that Forest could earn contingent upon future activity, including the number of additional wells drilled by Forest and connected to the buyer’s gathering facilities. During year ended December 31, 2013, Forest earned and received $2.5
million of these performance payments. As of December 31, 2013, there are $6.0 million of contingent performance payments that may still be earned. In conjunction with the sale, Forest entered into a ten-year natural gas gathering agreement with the buyer under which Forest pays market-based gathering rates and has committed the production from its existing and future operated wells located within five miles of the gathering system as it was configured at the time of sale. During the third quarter of 2012, these assets were written down to their estimated fair value less cost to sell, resulting in a $12.7 million impairment charge, which is included in the Consolidated
Statement of Operations within the “Impairment of properties” line item.
South Africa
In December 2012, Forest entered into an agreement with a third-party whereby Forest would receive $9.1 million in exchange for Forest abandoning its exploration right covering Block 2C in South Africa, contingent upon, among other things, the approval of the abandonment by the government of South Africa. Upon completion of certain contractual requirements, Forest received the $9.1 million in December 2013 and recorded a gain of $9.0 million, net of transaction costs, in other income within the “Other, net”
line item in the Consolidated Statement of Operations for the year ended December 31, 2013 since Forest had no proved reserves in South Africa and fully impaired its unproved properties in South Africa in 2012.
Forest also entered into a separate agreement in December 2012 to sell its South African subsidiary which holds a production right related to Block 2A in South Africa. Following approval of the sale by the government of South Africa, Forest will receive a payment of $1.0 million. If such approval is not received, closing on the sale will not occur. If closing occurs, Forest may receive further payments, as set forth in the agreement.
Miscellaneous
During
the year ended December 31, 2013, Forest also sold miscellaneous oil and natural gas properties for proceeds of $17.5 million. During the years ended December 31, 2012 and 2011, Forest also sold miscellaneous U.S. oil and natural gas properties for total proceeds of $25.6 million and $121.0 million, respectively.
Acquisition and Development Agreement
In April
2013, Forest entered into an Acquisition and Development Agreement (“ADA”) with a third-party for the future development of Forest’s Eagle Ford acreage in Gonzales County, Texas. Under the terms of the ADA, the third-party will pay a $90.0 million drilling carry in the form of future drilling and completion services and related development capital in exchange for a 50% working interest in Forest’s Eagle Ford acreage position. Upon completion of the phased contribution of the drilling carry, Forest and the third-party will participate in future drilling on a 50/50 basis. The ADA applies to wells spud on or subsequent to November 28, 2012, none of which had been placed on production prior to April 1, 2013, and Forest retained all of its interests in wells and production that
were spud prior to November 28, 2012. Forest is the operator of the drilling program. As of December 31, 2013, Forest had realized $61.1 million of the drilling carry and currently expects that it will be fully realized in 2014.
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.
(3)
In November 2013, Forest redeemed $422.1 million in principal amount of 7¼% senior notes due 2019 at 102.77%
of par, recognizing a net loss of $14.7 million upon redemption.
(4)
In November 2013, Forest redeemed $277.9 million in principal amount of 7½% senior notes due 2020 at 101.50% of par, recognizing a loss of $8.8 million upon redemption.
Bank Credit Facility
On June 30, 2011, the
Company 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 $300.0 million, to a total of $1.8 billion, upon agreement between the applicable lenders and Forest.
On September 12, 2013, the Company entered into the First Amendment to the Credit Facility (the “First Amendment”), which was effective as of that date. The First Amendment amended, among
other things, the permitted ratio of total debt to EBITDA and the definition of total debt used in the ratio calculation, and reduced the borrowing base, which governs Forest’s availability under the Credit Facility, to $700.0 million.
As of December 31, 2013, the borrowing base under the Credit Facility was $400.0 million. The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of Forest’s oil and natural gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and natural gas loans. The available borrowing
amount under the Credit Facility could increase or decrease based on such redetermination. In addition to the scheduled semi-annual redeterminations, Forest and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined. The borrowing base is also subject to automatic adjustments if certain events occur, such as if Forest or any of its Restricted Subsidiaries (as defined in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior notes, excluding any senior unsecured notes that Forest or any of its Restricted Subsidiaries may issue to
refinance senior notes that were outstanding on June 30, 2011. The borrowing base is also subject to automatic adjustment if Forest or any of its Restricted Subsidiaries sell oil and natural gas properties having a fair market value, including any economic loss of unwinding any related hedging agreement, in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount 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
75
the
sold properties, a value agreed upon by Forest and the required lenders. The February 2013 sale of Forest’s South Texas properties resulted in a $170.0 million reduction to the borrowing base effective February 15, 2013, and the November 2013 sale of Forest’s Panhandle properties resulted in a $300.0 million reduction to the borrowing base effective November 25, 2013. See Note 2 for more information regarding Forest’s property divestitures. The next scheduled semi-annual redetermination of the borrowing base will occur on or about May 1, 2014. A lowering of the borrowing base could require Forest to repay indebtedness in excess of the borrowing base in order to cover the deficiency.
The
Credit Facility is collateralized by Forest’s assets. Under the Credit Facility, Forest is required to mortgage and grant a security interest in 75% of the present value of the estimated proved oil and natural gas properties and related assets. If Forest’s corporate credit ratings issued by Moody’s and Standard &Poor’s meet pre-established levels, the security requirements would cease to apply and, at Forest’s request, the banks would release their liens and security interest on Forest’s properties.
Borrowings under the Credit Facility bear interest at one of two rates as may be elected by the Company. 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 Forest) (the “LIBO Rate”) plus 1%, plus, in the case of each of clauses (a), (b), and (c), 50 to 150 basis points depending on borrowing base utilization; or
(ii)
the
LIBO Rate as adjusted for statutory reserve requirements (the “Adjusted LIBO Rate”), plus 150 to 250 basis points, depending on borrowing base utilization.
The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant. The First Amendment to the Credit Facility provides that Forest will not permit its ratio of total debt to EBITDA (as adjusted for non-cash charges) calculated for the preceding four consecutive fiscal quarter period then most recently ended (i) for any time on or before September
11, 2013, to be greater than 4.50 to 1.00, (ii) for any time after September 11, 2013 and on or before March 31, 2014 to be greater than 5.00 to 1.00, (iii) for any time after April 1, 2014 and on or before June 30, 2014 to be greater than 4.75 to 1.00, and (iv) for any time after June 30, 2014, to be greater than 4.50 to 1.00. The First Amendment also amends
the definition of total debt such that, during any period of four fiscal quarters that includes the calendar quarter in which the Panhandle divestiture closed, any cash proceeds from the Panhandle divestiture that are reported on Forest’s consolidated balance sheet on such date are subtracted from total debt. Depending on Forest’s overall level of indebtedness, this covenant may limit Forest’s ability to borrow funds as needed under the Credit Facility. Forest’s ratio of total debt to EBITDA for the four consecutive fiscal quarter period ended December 31, 2013, as calculated in accordance with the Credit Facility, was 4.3. Based on Forest’s current projections, Forest expects the ratio of total debt to EBITDA to exceed the maximum allowed under the Credit Facility sometime during the second or third quarter of 2014 if it does
not obtain an additional amendment to the Credit Facility. Forest has initiated discussions to that effect with the administrative agent of the Credit Facility and, with no amounts currently drawn against the facility, believes that it will be able to obtain such an amendment prior to the ratio exceeding the maximum amount currently allowed. If Forest fails to obtain an amendment, the Credit Facility could be terminated. However, Forest believes it can obtain alternative sources of debt financing sufficient for its needs, including securing liens against its properties or selling additional properties. Additionally, if necessary, Forest has the ability to slow or cease the occurrence of certain capital and operational expenditures, including those related to initiating new drilling programs, to preserve its available cash until these other sources of funding become available at prudent terms.
Under
certain conditions, amounts outstanding under the Credit Facility may be accelerated with the resultant termination of the facility. Bankruptcy and insolvency events with respect to Forest or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility. In addition, certain
76
events of default under the Credit Facility will result in acceleration of the indebtedness under the Credit Facility, and termination of the 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, and a failure of the liens securing the Credit Facility.
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.
At December 31, 2013, there were no outstanding borrowings under the Credit Facility and Forest had used the Credit Facility for $2.1 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $397.9 million. At December 31, 2012, there were outstanding
borrowings of $65.0 million under the Credit Facility at a weighted average interest rate of 2.1% and Forest had used the Credit Facility for $1.6 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $1.0 billion.
8½% Senior Notes Due 2014
On February 17, 2009, Forest issued $600.0 million in principal amount of 8½% senior notes due 2014 (the “8½% Notes”) at 95.15% of par for net proceeds of $559.8
million, after deducting initial purchaser discounts. The 8½% Notes were redeemable, at the Company’s option, in whole or in part, at any time at the principal amount, plus accrued interest, and a make-whole premium. In October 2012, Forest redeemed $300.0 million of the 8½% Notes at 110.24% of par, recognizing a loss of $36.3 million upon redemption, using proceeds from the issuance of $500.0 million in principal amount of 7½% senior notes due 2020. In March 2013, Forest redeemed the remaining $300.0 million of 8½% Notes at 107.11% of par, recognizing a loss of $25.2
million upon redemption, using proceeds from the South Texas divestiture and borrowings under the Credit Facility.
7¼% Senior Notes Due 2019
On June 6, 2007, Forest issued $750.0 million in principal amount of 7¼% senior notes due 2019 (the
“7¼% Notes”) at par for net proceeds of $739.2 million, after deducting initial purchaser discounts, and on May 22, 2008, Forest issued an additional $250.0 million in principal amount of 7¼% Notes at 100.25%
of par for net proceeds of $247.2 million, after deducting initial purchaser discounts. Due to the amortization of the premium, the effective interest rate on the 7¼% Notes is 7.24%. Interest on the 7¼% Notes is payable semiannually on June 15 and December 15.
The 7¼% Notes are redeemable, at Forest’s option, at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued but unpaid interest, if redeemed during the twelve-month period beginning on June 15 of the years indicated below:
2012
103.625
%
2013
102.417
%
2014
101.208
%
2015
and thereafter
100.000
%
In November 2013, Forest carried out a tender offer to purchase up to $700.0 million aggregate principal amount of its 7¼% Notes and its 7½% senior notes using proceeds from the Panhandle divestiture. The tender offer for the 7¼% Notes was issued at 102.77% of par and Forest purchased $422.1 million of the 7¼% Notes, recognizing a net loss of $14.7 million upon redemption.
77
7½% Senior Notes Due 2020
On September 17, 2012, Forest issued $500.0 million in principal amount of 7½% senior notes due 2020 (the “7½% Notes”) at par for net proceeds of $491.3 million, after deducting initial purchaser discounts. Interest on the 7½% Notes is payable semiannually on March 15 and September 15.
The 7½% Notes are redeemable, at Forest’s option, at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued but unpaid interest, if redeemed
during the twelve-month period beginning on September 15 of the years indicated below:
2016
103.750
%
2017
101.875
%
2018 and thereafter
100.000
%
Forest
may also redeem the 7½% Notes, in whole or in part, at any time prior to September 15, 2016, at a price equal to the principal amount plus a make-whole premium, calculated using the applicable Treasury yield plus 0.5%, plus accrued but unpaid interest. In addition, prior to September 15, 2015, Forest may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 7½% Notes with the net proceeds of certain equity offerings at 107.5% of the principal amount of the 7½% Notes, plus any accrued but unpaid interest, if at least 65% of the aggregate principal amount of the 7½% Notes remains outstanding after such redemption and the redemption occurs within 120
days of the date of the closing of such equity offering.
In November 2013, Forest carried out a tender offer to purchase up to $700.0 million aggregate principal amount of its 7¼% Notes and its 7½% Notes using proceeds from the Panhandle divestiture. The tender offer for the 7½% Notes was issued at 101.50% of par and Forest purchased $277.9 million of the 7½% Notes, recognizing a loss of $8.8 million upon redemption.
Forest’s 8½% Notes, 7¼% Notes, and 7½% Notes
were fully and unconditionally guaranteed by a 100%-owned subsidiary of Forest, Forest Oil Permian Corporation (the “Guarantor Subsidiary”). Substantially all of the property of the Guarantor Subsidiary was sold in the Panhandle divestiture and, as a result, the Guarantor Subsidiary was merged into Forest effective December 31, 2013. As such, the guarantee no longer exists.
Principal Maturities
Principal maturities of Forest’s debt at December 31, 2013 are as follows:
Principal
Maturities
(In
Thousands)
2014
$
—
2015
—
2016
—
2017
—
2018
—
Thereafter
800,001
78
(4) INCOME TAXES:
Income Tax Provision
The table below sets forth the provision for income taxes attributable to continuing operations for the periods presented.
A
reconciliation of reported income tax attributable to continuing operations to the amount of income tax that would result from applying the United States federal statutory income tax rate to pretax earnings from continuing operations is as follows:
U.S. federal net operating loss carryforwards (“NOLs”) at December 31, 2013 were approximately $765.5 million, with $32.2 million of NOLs limited under Section 382 of the Internal Revenue Code scheduled to expire in 2019 and 2020 and the remaining scheduled to expire after 2029. Forest completed a Section 382 study in 2009. Because of the full valuation allowance placed against its deferred tax assets, Forest has not yet updated this study. Additionally, as of December 31, 2013,
the Company had state income tax NOLs of approximately $152.2 million, which, if unused, will expire between 2014 and 2031.
The statute of limitations is closed for the Company’s U.S. federal income tax returns for years ending on or before December 31, 2008. Pre-acquisition returns of acquired businesses are also closed for tax years ending on
80
or
before December 31, 2008. However, the Company has utilized, and will continue to utilize, NOLs (including NOLs of acquired businesses) in its open tax years. The earliest available NOLs were generated in the tax year beginning January 1, 1999, but are potentially subject to adjustment by the federal tax authorities in the tax year in which they are utilized. Thus, the Company’s earliest U.S. federal income tax return that is closed to potential audit adjustment is the tax year ending December 31, 1998.
Alternative Minimum Tax Credits
The
Alternative Minimum Tax credit carryforward available to reduce future U.S. federal regular taxes equaled an aggregate amount of $49.4 million at December 31, 2013, which can be carried forward indefinitely.
Accounting for Uncertainty in Income Taxes
The table below sets forth the reconciliation of the beginning and ending balances of the total amounts of unrecognized tax benefits. The Company records interest accrued related to unrecognized tax benefits in interest expense and penalties in other expense, to the extent they apply. The
Company does not expect a material amount of unrecognized tax benefits to reverse in the next twelve months.
Gross unrecognized tax benefits at beginning of period
$
859
$
2,829
$
3,345
Increases as a result of tax positions
taken during a prior period
31
—
—
Decreases as a result of tax positions taken during a prior period
—
(1,970
)
(516
)
Gross
unrecognized tax benefits at end of period
$
890
$
859
$
2,829
Income Tax Receivables
As
of December 31, 2013 and 2012, Forest had a non-current income tax receivable of $20.7 million which is included in “Other assets” in the Consolidated Balance Sheets.
(5) SHAREHOLDERS’ EQUITY:
Common Stock
At December 31, 2013, the
Company had 200.0 million shares of common stock, par value $.10 per share, authorized and 119.4 million shares issued and outstanding.
In February 2012, the Company issued 2.7 million shares of common stock, valued at $36.4 million, as partial consideration pursuant to a lease purchase agreement whereby Forest acquired leases on unproved oil and natural gas properties in the Permian Basin in Texas.
Preferred Stock
Forest
has 10.0 million shares of preferred stock, par value $.01 per share, authorized under its Certificate of Incorporation. The preferred stock is classified into two classes, Senior Preferred Stock and Junior Preferred Stock, each of which shall be issuable in one or more series. Subject to any limitation prescribed by law, the number of shares in each series and the designation and relative rights, preferences, and limitations of each series shall be fixed by the Board of Directors of Forest. The class of Senior Preferred Stock consists of 7.4 million shares and the class of Junior Preferred Stock consists of 2.7 million
shares. No preferred stock is issued or outstanding.
81
Lone Pine Resources Inc.
On June 1, 2011, Forest completed an initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone Pine, which held Forest’s ownership interests in its Canadian operations. In May 2011, as part of a corporate restructuring in anticipation of Lone Pine’s initial public offering, Lone Pine Resources Canada Ltd. (“LPR Canada”),
Forest’s former Canadian subsidiary, declared a stock dividend to Forest immediately before Forest’s contribution of LPR Canada to Lone Pine, with such stock dividend resulting in Forest incurring a dividend tax payable to Canadian federal tax authorities of $28.9 million, which Forest paid in June 2011. This dividend tax is classified within the “Income tax (benefit) expense” line item in the Consolidated Statement of Operations. The net proceeds from the initial public offering received by Lone Pine, after deducting underwriting discounts and commissions and offering expenses, were approximately $178.2 million. Lone Pine used the net proceeds to pay $29.2 million to Forest as partial consideration for Forest’s contribution to Lone Pine of Forest’s direct and indirect interests in its Canadian operations. Additionally, Lone
Pine used the remaining net proceeds and borrowings under its credit facility to repay its outstanding indebtedness owed to Forest, consisting of a note payable, intercompany advances, and accrued interest, of $400.5 million. On September 30, 2011, Forest distributed, or spun-off, its remaining 82% ownership in Lone Pine to Forest’s shareholders, by means of a special stock dividend whereby Forest shareholders received .61248511 of a share of Lone Pine common stock for every share of Forest common stock held. In accordance with applicable authoritative accounting guidance, Forest accounted for the spin-off based on the carrying value of Lone Pine.
The
table below sets forth the effects of changes in Forest’s ownership interest in Lone Pine on Forest’s equity, during the 2011 period in which Forest had an ownership interest in Lone Pine up to its spin-off on September 30, 2011.
Net earnings attributable to Forest Oil
Corporation common shareholders
$
118,375
Transfers from (to) the noncontrolling interest:
Increase in Forest Oil Corporation’s capital surplus for sale of 15 million Lone Pine Resources Inc. common shares
112,610
Decrease in Forest Oil Corporation’s capital surplus for spin-off of 70 million Lone Pine Resources Inc. common shares
(333,568
)
Change
from net earnings attributable to Forest Oil Corporation common shareholders and transfers from (to) noncontrolling interest
$
(102,583
)
(6) STOCK-BASED COMPENSATION:
Stock-based Compensation Plans
In 2001, the Company adopted the Forest Oil Corporation 2001 Stock Incentive Plan (the “2001 Plan”) and in 2007, the
Company adopted the Forest Oil Corporation 2007 Stock Incentive Plan (the “2007 Plan,” and together with the 2001 Plan, the “Stock-based Compensation 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. The aggregate number of shares of common stock that the Company may issue under the 2007 Plan may not exceed 9.5 million shares. As of December 31, 2013, the Company had 4.0 million shares available to be issued under the 2007 Plan. The aggregate number
of shares of common stock that the Company could issue under the 2001 Plan was 5.0 million, of which there are no remaining shares to be issued at December 31, 2013.
82
Compensation Costs
The table below sets forth stock-based compensation related to Forest’s continuing operations for the years ended December 31,
2013, 2012, and 2011, and the remaining unamortized amounts and weighted average amortization period as of December 31, 2013.
The
Company also maintains an employee stock purchase plan (which is not included in the table) under which $.2 million, $.4 million, and $.5 million of compensation costs were recognized for the years ended December 31, 2013, 2012, and 2011, respectively.
(2)
In connection with the 2013 divestitures of the South Texas and Texas Panhandle oil and natural gas properties, Forest incurred $4.9 million
($2.1 million net of capitalized amounts) in stock-based compensation costs due to accelerated vesting of involuntarily terminated employees’ awards. See Note 2 for more information regarding these divestitures.
(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.
83
Stock Options
The
following table summarizes stock option activity in the Stock-based Compensation Plans for the years ended December 31, 2013, 2012, and 2011.
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.
(2)
In conjunction with the spin-off of Lone Pine, both the number of options outstanding and the option exercise prices were adjusted in accordance with antidilution provisions provided in the Stock-based Compensation Plans.
Stock options are granted at the fair market value of one share of common stock on the date of grant and have a term of ten years. Options
granted to non-employee directors vest immediately and options granted to officers and other employees vest in increments of 25% on each of the first four anniversary dates of the grant.
The following table summarizes information about options outstanding at December 31, 2013:
Stock
Options Outstanding and Exercisable
Range of Exercise Prices
Number of Options
Weighted Average Remaining Contractual Life (Years)
Weighted Average Exercise Price
Aggregate Intrinsic Value (In Thousands)
$11.02 - 12.20
131,223
0.18
$
11.12
$
—
12.21
- 13.47
27,383
0.30
12.80
—
13.48 - 13.68
205,508
0.76
13.56
—
13.69
- 24.30
128,565
2.02
19.54
—
24.31 - 27.90
138,527
2.76
27.11
—
$11.02
- 27.90
631,206
1.31
$
17.21
$
—
84
Restricted Stock, Performance Units, and Phantom Stock Units
The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Stock-based Compensation Plans for the years ended December 31, 2013, 2012, and 2011.
In
conjunction with the spin-off of Lone Pine, the number of performance units and phantom stock units outstanding was adjusted in accordance with antidilution provisions provided in the Stock-based Compensation Plans. In addition, the initial stock prices used to measure Forest’s total shareholder returns over the performance periods of the performance units were adjusted in accordance with the antidilution provisions provided in the Stock-based Compensation Plans. The number of restricted stock awards outstanding was not adjusted as a result of the spin-off since holders of restricted stock awards received Lone Pine common shares in the spin-off.
(2)
In conjunction with the spin-off of Lone Pine, Lone Pine employees were deemed to have been
involuntarily terminated under the terms of their phantom stock and performance unit agreements, and, therefore, all such awards held by Lone Pine employees vested on September 30, 2011. The phantom stock awards were settled in cash by Lone Pine. No shares were deliverable under the performance unit agreement. No Forest restricted stock awards were held by Lone Pine employees at the time of the spin-off.
Restricted Stock
The grant date fair value of restricted stock is determined by averaging the high and low stock price of a share of Forest common stock as published by the New York Stock Exchange on the date of grant. Of the unvested restricted stock as of December 31,
2013, 851,526 shares, which were granted in 2013, vest in increments of one-third on each of the first three anniversary dates of the grant. All other unvested shares of restricted stock cliff vest on the third anniversary of the date of grant. Restricted stock may vest earlier upon a qualifying disability, death, certain involuntary terminations, or a change in control of the Company in accordance with the terms of the underlying agreement.
85
Performance Units
Forest
grants performance units to its officers. Under the terms of the award agreements, each performance unit represents a contractual right to receive either one share of Forest’s common stock or the cash value of one share of Forest’s common stock, depending on the particular agreement, provided that the actual number of shares or cash equivalent amount that may be deliverable under an award will range from 0% to 200% of the number of performance units awarded, depending on Forest’s relative total shareholder return in comparison to an identified peer group over a thirty-six month performance period. The grant date fair values of these awards were determined using a process that takes into account probability-weighted shareholder returns assuming a large number of possible stock price
paths, which are modeled based on inputs such as volatility and the risk-free interest rate. The cash-based performance units are accounted for as a liability within the Consolidated Financial Statements. Of the unvested performance units at December 31, 2013, 706,000, which were granted in 2013, are cash-based and the remaining 805,140 are share-based. Like restricted stock, performance units may vest earlier due to certain circumstances, as discussed above.
Phantom Stock Units
The grant and reporting date fair values of the phantom stock units are determined by averaging the high and low stock
price of a share of Forest common stock as published by the New York Stock Exchange on the applicable date. All of the unvested phantom stock units at December 31, 2013 must be settled in cash and, therefore, are accounted for as a liability within the Consolidated Financial Statements. All of the phantom stock units that vested during 2013 were settled in cash. In 2012, 6,080 phantom stock units were settled in shares of common stock and 602,463 phantom stock units were settled in cash. In 2011, 5,500 phantom stock units were settled in shares of common stock and 393,357
phantom stock units were settled in cash.
Of the unvested phantom stock units at December 31, 2013, (i) 152,393 were granted in 2011 and 851,426 were granted in 2013 and vest in one-third increments on each of the first three anniversaries of the date of grant, (ii) 493,000 were granted in 2013 and cliff vest on the third anniversary of the date of the award, (iii) and 378,000 were granted in 2012 and 50,000 were granted in 2013 and vest over a four-year period in accordance with the following schedule: (a) 10%
on the first anniversary of the grant date; (b) 20% on the second anniversary of the grant date; (c) 30% on the third anniversary of the grant date; and (d) 40% on the fourth anniversary of the grant date. Like restricted stock, phantom stock units may vest earlier due to certain circumstances, as discussed above.
Employee Stock Purchase Plan
The Company has a 1999 Employee Stock Purchase Plan (the “ESPP”), under which it is authorized to issue up to 1.6 million shares of common stock. Employees who are regularly
scheduled to work more than 20 hours per week and more than five months in any calendar year may participate in the ESPP. Currently, under the terms of the ESPP, employees may elect each calendar quarter to have up to 15% of their annual base earnings withheld to purchase shares of common stock, up to a limit of $25,000 of common stock per calendar year. The purchase price of a share of common stock purchased under the ESPP is equal to 85% of the lower of the beginning-of-quarter or end-of-quarter market price. ESPP participants are restricted from selling the shares of common stock purchased under the ESPP for a period of six months after purchase. As of December 31,
2013, the Company had .7 million shares available for issuance under the ESPP.
86
The fair value of each stock purchase right granted under the ESPP during 2013, 2012, and 2011 was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair market value of purchase rights granted during the periods presented:
Weighted
average fair market value of purchase rights granted
$1.29
$2.43
$5.00
(7) EMPLOYEE BENEFITS:
Pension Plans and Postretirement Benefits
The Company has a qualified defined benefit pension plan that covers
certain employees and former employees in the United States (the “Forest Pension Plan”). The Company also has a non-qualified unfunded supplementary retirement plan (the “SERP”) that provides certain retired executives with defined retirement benefits in excess of qualified plan limits imposed by federal tax law. The Forest Pension Plan and the SERP were curtailed and all benefit accruals under both plans were suspended effective May 31, 1991. In addition, as a result of The Wiser Oil Company acquisition in 2004, Forest assumed a noncontributory defined benefit pension plan (the “Wiser Pension Plan,” and together with the “Forest Pension Plan,” the “Pension Plans”). The Wiser Pension Plan was curtailed and all benefit accruals were suspended effective December 11, 1998. The Forest Pension Plan, the Wiser
Pension Plan, and the SERP are hereinafter collectively referred to as the “Plans.”
In addition to the Plans described above, Forest also provides postretirement benefits to certain employees in the U.S. hired on or prior to January 1, 2009, their beneficiaries, and covered dependents. These benefits, which consist primarily of medical benefits payable on behalf of retirees in the U.S., are referred to as the “Postretirement Benefits Plan” throughout this Note.
Expected Benefit Payments
As of December 31, 2013, it is anticipated that the
Company will be required to provide benefit payments from the Forest Pension Plan trust and the Wiser Pension Plan trust and fund benefit payments directly for the SERP and the Postretirement Benefits Plan in the following amounts:
2014
2015
2016
2017
2018
2019-
2023
(In
Thousands)
Forest Pension Plan(1)
$
2,336
$
2,291
$
2,230
$
2,159
$
2,116
$
9,433
Wiser
Pension Plan(1)
867
861
851
837
818
3,833
SERP
133
129
124
120
114
490
Postretirement
Benefits Plan
727
713
706
726
734
3,849
____________________________________________
(1)
Benefit
payments expected to be made to participants in the Forest Pension Plan and Wiser Pension Plan are expected to be paid out of funds held in trusts established for each plan.
Forest anticipates that it will make contributions in 2014 totaling $1.7 million to the Plans and $.6 million to the Postretirement Benefits Plan, net of retiree contributions, as applicable.
87
Benefit Obligations
The
following table sets forth the estimated benefit obligations associated with the Company’s Pension Plans and Postretirement Benefits Plan.
Year Ended December 31,
Pension
Plans
Postretirement
Benefits Plan
2013
2012
2013
2012
(In Thousands)
Benefit
obligation at the beginning of the year
$
46,017
$
44,755
$
17,227
$
13,498
Service
cost
—
—
1,094
1,131
Interest cost
1,329
1,554
603
547
Actuarial
(gain) loss
(2,983
)
2,902
(2,935
)
2,613
Benefits paid
(3,285
)
(3,194
)
(602
)
(619
)
Retiree
contributions
—
—
49
57
Benefit obligation at the end of the year
$
41,078
$
46,017
$
15,436
$
17,227
Fair
Value of Plan Assets
The Company’s Pension Plans’ assets measured at fair value on a recurring basis are set forth by level within the fair value hierarchy in the table below as of the dates indicated (see Note 8 for information on the fair value hierarchy). There were no changes to the valuation techniques used during the period. There are no assets set aside under the SERP and the Postretirement Benefits Plan.
The
total fair value of the Pension Plans’ assets of $31.4 million as of December 31, 2013 does not include net accrued expenses of $.1 million. The total fair value of the Pension Plans’ assets of $28.0 million as of December 31, 2012 does not include net accrued expenses of $.2 million.
(2)
This investment fund’s assets are primarily large capitalization U.S. equities. The
investment approach of this fund, which typically holds 110 - 130 securities, focuses on diversifying the investment portfolio by delegating the equity selection process to research analysts with expertise in their respective industries. Industry weights are kept similar to those of the S&P 500 Index. As of
88
December 31, 2013, the sector weighting of this fund was comprised of the following: information technology (19%), financials (16%), health care
(15%), consumer discretionary (11%), industrials (11%), consumer staples (11%), and other (17%). The fair value of this investment fund was determined based on the net asset value per unit provided by the investee. Forest performs procedures to validate the net asset value per unit provided by the investee. Such procedures include verifying a sample of the net asset values of the underlying securities, which are directly observable in the marketplace.
(3)
These three investment funds
seek long-term growth of principal and income by investing primarily in diversified portfolios of equity securities issued by foreign, medium-to-large companies in international markets including emerging markets. The first fund typically holds 50 - 100 securities and seeks to invest in solid, well-established global leaders with emphasis on strong corporate governance, positive future growth opportunities, and growing return on capital. As of December 31, 2013, the sector weighting of this fund, which seeks diversification across regions, countries, and market sectors, was comprised of the following: financials (24%), health care (16%), information technology (15%),
consumer discretionary (13%), industrials (11%), and other (21%). The second fund seeks to obtain growth through long-term appreciation of its holdings, selecting investments based upon their current fundamentals. As of December 31, 2013, the sector weighting of this fund, which invests in Asian (excluding Japanese) growth equities with a focus on domestic demand growth rather than an export orientation, was comprised of the following: financials (27%), information technology (18%), consumer staples (18%), consumer discretionary (11%), and other (26%).
The third fund seeks to deliver equity-like returns with significantly less volatility by investing in emerging markets equity securities. As of December 31, 2013, the sector weighting of this fund, which holds approximately 80 positions across the portfolio, with country allocations not exceeding 25%, was comprised of the following: financials (17%), materials (14%), consumer discretionary (14%), information technology (13%), industrials (13%), energy (12%), and other (17%).
The fair value of these investment funds was determined based on the funds’ net asset values per unit, which are directly observable in the marketplace.
(4)
This investment fund’s assets are high-quality money market instruments and short-term fixed income securities. This fund is actively managed as an enhanced cash strategy, seeking to derive excess returns versus money market fund indices by capturing term, transactional liquidity, credit, and volatility premiums. As of December 31, 2013, the sector weighting of this fund was comprised of the following: government related (28%), investment grade (23%),
mortgage (13%), and other (36%). The fair value of this investment fund was determined based on the fund’s net asset value per unit, which is directly observable in the marketplace.
(5)
These two investment funds consist of diversified portfolios of bonds. The first fund’s main investments are intermediate maturity fixed income securities with a duration between three and six years, with a maximum of 10% of the portfolio being invested in securities below Baa grade,
and up to 30% of the portfolio being invested in non-U.S. dollar denominated securities. As of December 31, 2013, the sector weighting of this fund was comprised of the following: government-related (42%), mortgage (33%), and other (25%). The second fund seeks to deliver equity-like returns with significantly less volatility by investing in emerging markets debt securities. As of December 31, 2013, the sector weighting of this fund, which holds approximately 80 positions across the portfolio, with country allocations not exceeding 25%,
was comprised of the following: sovereign-local (40%), corporates (28%), inflation linked (22%), and sovereign U.S. dollar denominated (10%). The fair value of these investment funds was determined based on the funds’ net asset values per unit, which are directly observable in the marketplace.
(6)
The oil and gas royalty interests are valued at their estimated discounted future cash flows, which approximate fair value.
The following table sets forth
a rollforward of the fair value of the plan assets.
Year Ended December 31,
Pension Plans
Postretirement
Benefits
Plan
2013
2012
2013
2012
(In Thousands)
Fair value of plan assets at beginning of the year
$
27,791
$
25,957
$
—
$
—
Actual
return on plan assets
4,736
4,048
—
—
Retiree contributions
—
—
49
57
Employer
contribution
2,107
980
553
562
Benefits paid
(3,285
)
(3,194
)
(602
)
(619
)
Fair
value of plan assets at the end of the year
$
31,349
$
27,791
$
—
$
—
89
The following table presents a reconciliation of the beginning and ending balances of the Company’s Pension Plan assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
The Pension Plans’ assets are invested with a view toward the long term in order to fulfill the obligations promised to participants as well as to control future funding levels. The Company continually reviews the levels of funding and investment strategy for the Pension Plans. Generally, the strategy includes allocating the Pension Plans’ assets between equity securities and fixed income securities, depending on economic conditions and funding needs, although the strategy does not define any specified minimum exposure for any point in time. The equity and fixed income asset allocation levels in place from time to time are intended to achieve an appropriate balance between capital appreciation, preservation of capital, and current income.
The
overall investment goal for the Pension Plans’ assets is to achieve an investment return that allows the assets to achieve the assumed actuarial interest rate and to exceed the rate of inflation. In order to manage risk, in terms of volatility, the portfolios are designed with the intent of avoiding a loss of 20% during any single year and expressing no more volatility than experienced by the S&P 500 Index. The Pension Plans’ investment allocation target is up to 75% equity, with discretion to vary the mix temporarily, in response to market conditions.
The weighted average asset allocations of the Forest Pension Plan and Wiser Pension Plan are set forth in the following table as of the dates indicated:
December
31,
Forest
Pension Plan
Wiser
Pension Plan
2013
2012
2013
2012
Fixed
income securities
22
%
24
%
21
%
25
%
Equity securities
77
%
75
%
78
%
74
%
Other
1
%
1
%
1
%
1
%
100
%
100
%
100
%
100
%
90
Funded Status
The following table sets forth the funded status of the Company’s Pension Plans and Postretirement Benefits Plan.
December
31,
Pension Plans
Postretirement Benefits Plan
2013
2012
2013
2012
(In
Thousands)
Excess of benefit obligation over plan assets
$
(9,728
)
$
(18,225
)
$
(15,436
)
$
(17,227
)
Unrecognized
actuarial loss
18,025
24,811
2,303
5,633
Net amount recognized
$
8,297
$
6,586
$
(13,133
)
$
(11,594
)
Amounts
recognized in the balance sheet consist of:
Accrued benefit liability—current
$
(133
)
$
—
$
(641
)
$
—
Accrued
benefit liability—noncurrent
(9,595
)
(18,225
)
(14,795
)
(17,227
)
Accumulated other comprehensive income—net actuarial loss
18,025
24,811
2,303
5,633
Net
amount recognized
$
8,297
$
6,586
$
(13,133
)
$
(11,594
)
The
following table sets forth the projected and accumulated benefit obligations for the Pension Plans compared to the fair value of the plan assets as of the dates indicated.
The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions.
Year
Ended December 31,
Pension Plans
Postretirement Benefits Plan
2013
2012
2011
2013
2012
2011
(Dollar
Amounts In Thousands)
Service cost
$
—
$
—
$
—
$
1,094
$
1,131
$
825
Interest
cost
1,329
1,554
1,836
603
547
529
Expected
return on plan assets
(1,912
)
(1,744
)
(2,014
)
—
—
—
Recognized
actuarial loss
979
979
651
395
194
—
Total
net periodic expense
$
396
$
789
$
473
$
2,092
$
1,872
$
1,354
Assumptions
used to determine net periodic expense:
Discount rate
2.98%
3.58%
4.50%
3.68%
4.14%
5.15%
Expected
return on plan assets
7%
7%
7%
n/a
n/a
n/a
Assumptions used to determine benefit obligations:
Discount
rate
3.79%
2.98%
3.58%
4.48%
3.68%
4.14%
91
The discount rates used to determine benefit obligations were determined by adjusting composite AA bond yields to reflect the difference between the duration of the future estimated cash flows of the Plans and the Postretirement Benefits Plan obligations and the duration of the composite AA bond yields. The expected rate of return on plan assets was determined based on historical returns.
The Company estimates that net periodic expense for the year ended December 31, 2014 for the Pension Plans and for the Postretirement Benefits Plan will include expense of $.7
million and $.1 million, respectively, resulting from the amortization of the related accumulated actuarial loss included in accumulated other comprehensive income at December 31, 2013.
The assumed health care cost trend rate for the next year and thereafter that was used to measure the expected cost of benefits covered by the Postretirement Benefits Plan was 5.5%. Assumed health care cost trend rates can have a significant effect on the amounts reported for the Postretirement Benefits Plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Forest sponsors various defined contribution plans under which the Company contributed matching contributions equal to $2.7 million in 2013, $3.7
million in 2012, and $3.7 million in 2011.
Forest also provides life insurance benefits for certain retirees and former executives under split dollar life insurance plans. Under the life insurance plans, the Company is assigned a portion of the benefits. No current employees are covered by these plans. The Company has recognized a liability for the estimated cost of maintaining the insurance policies during the postretirement periods of the retirees and former executives, with such liability accreted each period to its present value. The
Company’s estimate of costs expected to be paid in 2014 to maintain these life insurance policies is $1.0 million. Forest recognized accretion expense related to the split dollar life insurance obligations of $1.1 million, $.9 million, and $1.0 million for the years ended December 31, 2013, 2012, and 2011, respectively. The split dollar life insurance obligation recognized in the Consolidated Balance Sheets was $7.3 million as of December 31,
2013 and 2012. The discount rates used to determine the obligations were 3.44% and 2.57% as of December 31, 2013 and 2012, respectively. The cash surrender value of the split dollar life insurance policies recognized in the Consolidated Balance Sheets was $6.5 million and $3.6 million as of December 31, 2013 and 2012,
respectively.
92
(8) FAIR VALUE MEASUREMENTS:
Forest’s assets and liabilities measured at fair value on a recurring basis at December 31, 2013 and 2012 are set forth in the table below.
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 2013. Forest’s policy is to recognize transfers between levels of the fair value hierarchy as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
(2)
Forest’s currently outstanding
derivative assets and liabilities are commodity price derivatives (see Note 9 for more information on these instruments). Forest utilizes present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, Forest’s derivative instruments are included within the Level 2 fair value hierarchy.
The fair values and carrying amounts of the Forest’s financial instruments are summarized below as of the dates indicated.
Using
Quoted Prices in Active Markets for Identical Assets (Level 1)
Using Significant Other Observable Inputs (Level 2)
(In Thousands)
Assets:
Derivative
instruments
$
5,592
$
5,592
$
—
$
5,592
Liabilities:
Derivative
instruments
4,542
4,542
—
4,542
7¼% senior notes due 2019
578,092
568,147
568,147
—
7½%
senior notes due 2020
222,087
224,030
224,030
—
____________________________________________
(1)
Forest
used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on quoted market prices. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 9 for more information on the derivative instruments.
Using
Quoted Prices in Active Markets for Identical Assets (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 9 for more information on the derivative instruments.
(9) 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 line item “Realized and unrealized losses (gains) on derivative instruments, net” in the Consolidated Statement of Operations.
The table below sets forth Forest’s outstanding commodity swaps as of December 31, 2013.
Commodity
Swaps
Natural Gas (NYMEX HH)
Oil (NYMEX WTI)
Swap Term
Bbtu
Per Day
Weighted
Average
Hedged Price
per
MMBtu
Barrels
Per Day
Weighted
Average
Hedged Price
per Bbl
Calendar 2014
70
$
4.38
3,500
$
95.34
Calendar
2015
20
4.20
—
—
94
In connection with several natural gas and oil swaps entered into, Forest granted option instruments (several swaptions and puts) to the swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas and oil swaps. Under the terms of the swaption agreements, the counterparties have the option to enter into future swaps with Forest. The swaptions may not be exercised until their expiration dates. Under the terms of the put agreements, the counterparties have the option to put specified quantities of oil to Forest at specified prices. The puts may be exercised monthly by the counterparties. The table below sets forth the outstanding commodity options as of December 31, 2013.
Represents
the hedged floor and ceiling price per MMBtu.
Interest Rate Derivatives
Forest voluntarily terminated its interest rate swaps in June 2013 for proceeds of $11.4 million, which are included as realized gains in the line item “Realized and unrealized losses (gains) on derivative instruments, net” in the Consolidated Statement of Operations for the year ended December 31, 2013. The original maturity date of the interest rate swaps was February 2014.
95
Fair Value and Gains and Losses
The table below summarizes the location and fair value amounts of Forest’s derivative instruments reported in the 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 8 for more information on the fair values of Forest’s derivative instruments.
The
table below summarizes the amount of derivative instrument gains and losses reported in the Consolidated Statements of Operations as realized and unrealized (gains) losses on derivative instruments, net, for the periods indicated. Realized gains and losses represent cash settlements on derivative instruments and unrealized gains and losses represent changes in fair value of derivative instruments. These derivative instruments are not designated as hedging instruments for accounting purposes.
Realized and unrealized losses (gains) on derivative instruments, net
$
3,786
$
(72,646
)
$
(88,064
)
96
Due to the volatility of oil and natural gas prices, the estimated fair values of Forest’s commodity derivative instruments are subject to large fluctuations from period to period. Forest has experienced the effects of these commodity price fluctuations and expects that volatility in commodity prices will continue.
Credit Risk
Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. (“ISDA”) Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally,
Forest executes, with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties’ requirements and the specific types of derivatives to be transacted. As of December 31, 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 $4.5 million at December 31, 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 December 31, 2013, Forest
owed a net derivative liability to its counterparties, the fair value of which was $3.5 million. In the absence of netting provisions, at December 31, 2013, Forest would be exposed to a risk of loss of $5.6 million under its derivative agreements, and Forest’s derivative counterparties would be exposed to a risk of loss of $4.5 million.
97
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 Consolidated Balance Sheets as of the dates indicated.
Net amounts of liabilities presented in the balance sheet
4,542
16,551
Gross amounts not offset in
the balance sheet:
Derivative instruments
(1,049
)
(13,537
)
Cash collateral pledged
—
—
Net
amount
$
3,493
$
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. However, the legislation could have a substantial impact on Forest’s counterparties and increase the cost of Forest’s derivative agreements in the future.
98
(10) COMMITMENTS AND CONTINGENCIES:
The table below sets forth Forest’s future payments under non-cancelable operating leases and unconditional purchase obligations as of December 31,
2013.
2014
2015
2016
2017
2018
After
2018
Total
(In Thousands)
Operating leases(1)
$
22,655
$
15,823
$
15,190
$
8,174
$
2,083
$
7,873
$
71,798
Unconditional
purchase obligations(2)
5,840
5,805
5,700
—
—
—
17,345
$
28,495
$
21,628
$
20,890
$
8,174
$
2,083
$
7,873
$
89,143
____________________________________________
(1)
Includes
future rental payments for office facilities and equipment, drilling rigs, and compressors under the remaining terms of non-cancelable operating leases with initial terms in excess of one year. In January 2014, Forest terminated certain drilling rig operating leases for a net loss of approximately $5.0 million, which will reduce the operating lease obligations shown in the table above by $12.4 million in 2014, $10.8 million in 2015, $10.8 million in 2016, and $6.1 million in 2017.
(2)
Includes
unconditional purchase obligations for drilling commitments and voice and data services. Payments made under these unconditional purchase obligations were $5.8 million in 2013, $.4 million in 2012, and $.4 million in 2011.
Net rental payments under non-cancelable operating leases applicable to exploration and development activities and capitalized to oil and natural gas properties approximated $10.4 million in 2013, $15.6 million in 2012,
and $21.0 million in 2011. Net rental payments under non-cancelable operating leases, including drilling rigs and compressor rentals, charged to expense approximated $24.5 million in 2013, $22.0 million in 2012, and $16.5 million in 2011. Forest has no leases that are accounted for as capital leases.
Forest, in the ordinary course of business, is a party to various lawsuits, claims, and proceedings. While the Company believes
that the amount of any potential loss upon resolution of these matters would not be material to its consolidated financial position, the ultimate outcome of these matters is inherently difficult to predict with any certainty. In the event of an unfavorable outcome, the potential loss could have an adverse effect on Forest’s results of operations and cash flow. Forest is also involved in a number of governmental proceedings in the ordinary course of business, including environmental matters.
(11) COSTS, EXPENSES, AND OTHER:
The table below sets forth the components of “Other, net” in the Consolidated Statements of Operations for the periods indicated.
Forest recognized a $193.0 million net gain on its Panhandle divestiture and a $9.0 million net gain on the disposition of its Block 2C Exploration Right in South Africa. See Note 2 for more information regarding Forest’s asset divestitures.
Loss on Debt Extinguishment, Net
In November 2013, Forest redeemed $422.1 million in principal amount of 7¼% senior notes at 102.77% of par, recognizing a net
loss of $14.7 million upon redemption due to the $11.7 million early tender premium and write-off of $3.0 million of unamortized debt issue costs and premium, net. Also in November 2013, Forest redeemed $277.9 million in principal amount of 7½% senior notes at 101.50% of par, recognizing a loss of $8.8 million upon redemption due to the $4.2 million early tender premium and write-off of $4.6 million of unamortized debt issue costs.
In March 2013, Forest redeemed $300.0 million
in principal amount of 8½% senior notes at 107.11% of par, recognizing a loss of $25.2 million upon redemption due to the $21.3 million call premium and write-off of $3.9 million of unamortized debt issue costs and discount.
In October 2012, Forest redeemed $300.0 million in principal amount of 8½% senior notes at 110.24% of par, recognizing a loss of $36.3 million upon redemption due to the $30.7 million call premium and write-off of $5.6 million of unamortized debt
issue costs and discount.
Legal Proceeding Liabilities
Legal proceeding liabilities for the year ended December 31, 2012 includes $22.8 million for the previously-disclosed arbitration award against Forest in Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al. Forest is seeking to have this award reversed on appeal and believes it has meritorious arguments in support thereof. However, Forest is unable to predict the final outcome in this matter and has accrued a liability, which is classified within “Other liabilities” in the Consolidated Balance Sheet, of $24.2
million, which includes accrued interest, for this matter. Also included in legal proceeding liabilities for the year ended December 31, 2012 is a $7.0 million settlement payment that Forest paid to the plaintiff in exchange for the plaintiff releasing Forest from all claims, indemnifying Forest with respect to all decommissioning and abandonment liabilities associated with Trading Bay, and dismissing the complaint in the previously-disclosed matter Union Oil Company of California v. Forest Oil Corporation.
Legal proceeding liabilities for the year ended December 31, 2011
consists of a $6.5 million settlement payment that Forest paid to the plaintiffs in exchange for the plaintiffs releasing Forest from all claims and dismissing the complaint against Forest in the previously-disclosed matter involving the Alaska assets that Forest sold to Pacific Energy Resources Ltd.
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. See Note 1 for more information on Forest’s asset retirement obligations.
100
(12) SELECTED QUARTERLY FINANCIAL DATA (unaudited):
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(In
Thousands, Except Per Share Amounts)
2013
Oil, natural gas, and natural gas liquids sales
$
118,042
$
116,786
$
118,028
$
88,485
Costs
and expenses associated directly with products sold(1)
$
75,482
$
69,514
$
69,881
$
57,299
Earnings
(loss) before income taxes(2)
$
(67,611
)
$
33,227
$
1,627
$
105,974
Net
earnings (loss)(2)
$
(67,948
)
$
33,439
$
2,214
$
106,219
Basic
and diluted earnings (loss) per share
$
(.59
)
$
.28
$
.02
$
.89
2012
Oil,
natural gas, and natural gas liquids sales
$
158,901
$
135,694
$
156,014
$
154,914
Costs
and expenses associated directly with products sold(1)
$
110,110
$
110,996
$
114,304
$
104,048
Earnings
(loss) before income taxes(2)
$
(31,758
)
$
(344,099
)
$
(451,272
)
$
(288,365
)
Net
earnings (loss)(2)
$
(32,673
)
$
(511,173
)
$
(458,552
)
$
(286,533
)
Basic
and diluted earnings (loss) per share
$
(.29
)
$
(4.44
)
$
(3.97
)
$
(2.48
)
___________________________________________
(1)
Costs
and expenses associated directly with products sold is comprised of lease operating expenses, production and property taxes, transportation and processing costs, depletion expense, and accretion of asset retirement obligations.
(2)
Earnings (loss) before income taxes and net earnings (loss) have been impacted by non-cash ceiling test write-downs in every quarter of 2012 and the fourth quarter of 2013, as discussed in Note 1, and are also subject to large fluctuations due to Forest’s election not to use cash flow hedge accounting for derivative instruments as discussed in Note 9. Also impacting the fourth quarter of 2013
is a $193.0 million net gain on the Panhandle divestiture, as discussed in Note 2.
(13) DISCONTINUED OPERATIONS:
Lone Pine was a component of Forest, representing Forest’s entire Canadian cost center, with operations and cash flows clearly distinguishable, both operationally and for financial reporting purposes, from those of Forest. As a result of the spin-off of Lone Pine on September 30, 2011, Lone Pine’s operations and cash flows were eliminated from the ongoing operations of Forest, and Forest did not have any significant continuing involvement in the operations
of Lone Pine. Accordingly, Forest has presented Lone Pine’s results of operations as discontinued operations in the Consolidated Statement of Operations for the year ended December 31, 2011. For more information regarding the spin-off see Note 5.
101
The table below presents the major components of earnings from discontinued operations for the period presented.
Realized and unrealized gains on derivative instruments, net
(33,628
)
Realized foreign currency exchange gains
(33,869
)
Unrealized
foreign currency exchange losses, net
28,488
Other, net
1,328
Earnings from discontinued operations before tax
61,673
Income tax expense
17,104
Net
earnings from discontinued operations
$
44,569
102
(14) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited):
Supplemental unaudited information regarding Forest’s oil and gas producing activities is presented in this Note. This supplemental information excludes amounts for all periods presented
related to Forest’s discontinued operations.
Estimated Proved Reserves
Proved reserves are those quantities of oil, natural gas liquids, and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced
or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price for oil, natural gas liquids, and natural gas during the twelve month period prior to the end of the reporting period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. Existing economic conditions include year-end cost estimates.
Proved developed reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or
in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
The following table sets forth the Company’s estimates of its net proved, net proved developed, and net proved undeveloped oil, natural gas liquids, and natural gas reserves as of December 31,
2013, 2012, and 2011 and changes in its net proved reserves for the years then ended. For the years presented, the Company engaged DeGolyer and MacNaughton, an independent petroleum engineering firm, to perform reserve audit services.
Oil
and natural gas liquids are converted to gas-equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. Likewise, natural gas is converted to oil-equivalents using a conversion of one barrel of oil “equivalent” per six Mcf of natural gas. These conversions are based on energy equivalence and not price equivalence.
104
Revisions of Previous Estimates
In 2013, net negative revisions of 10 Bcfe
were comprised of (i) the reclassification of 41 Bcfe of proved undeveloped reserves (“PUDs”) to probable undeveloped reserves for PUDs that are not expected to be developed five years from the time the reserves were initially disclosed, (ii) negative performance revisions of 9 Bcfe, and positive pricing revisions of 40 Bcfe due primarily to the increase in price of natural gas used in calculating proved reserves. In 2012, net negative revisions of 604 Bcfe were primarily associated with lower natural gas and natural gas liquids prices, which caused certain natural gas-weighted projects to no longer meet economic investment criteria based on the unweighted arithmetic average of the first-day-of-the-month commodity prices utilized in
calculating the reserve estimates. In addition, lower natural gas prices also delayed Forest’s initial expected development time frame for drilling certain of its proved undeveloped natural gas locations beyond five years from the time the associated reserves were originally recorded. Accordingly, these PUDs were reclassified to probable undeveloped reserves in 2012. Additionally, all 52 Bcfe of the Company’s Italian PUDs were reclassified to probable due to an Italian regional regulatory body’s 2012 denial of the Company’s environmental impact assessment associated with the Company’s proposal to commence natural gas production from wells that it drilled and completed in 2007.
The Company is currently appealing the region’s denial; however, until the region’s denial is reversed or overturned, the Company determined that it could no longer conclude with reasonable certainty that its Italian natural gas reserves are producible. In 2011, the net negative revisions of 120 Bcfe were primarily the result of the write-off of PUDs pursuant to the five year limitation and the write-off of natural gas reserves associated with a deep gas project in South Louisiana.
Extensions and Discoveries
In 2013, the
Company had 148 Bcfe of extensions and discoveries, which were primarily due to exploration and development activities in the Eagle Ford in South Texas and Cotton Valley in East Texas. In 2012, the Company had 235 Bcfe of extensions and discoveries, which were primarily due to exploration and development activities in the Texas Panhandle and Eagle Ford in South Texas. In 2011, the Company had 301 Bcfe of extensions and discoveries, which were also primarily due to exploration and development activities in the Texas Panhandle and Eagle Ford in South Texas.
Sales
of Reserves in Place
Sales of reserves in place for each of the years presented in the table above represent the sale of oil and natural gas property interests. See Note 2 for a description of these asset divestitures.
Aggregate Capitalized Costs
The aggregate capitalized costs relating to oil and gas producing activities were as follows as of the dates indicated:
Includes
inception-to-date ceiling test write-downs.
105
Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities
The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2013, 2012, and 2011:
United
States
Italy
Total
(In
Thousands)
2013
Property acquisition costs:
Proved properties
$
—
$
—
$
—
Unproved
properties
7,117
—
7,117
Exploration costs
129,946
—
129,946
Development
costs
213,127
—
213,127
Total costs incurred(1)
$
350,190
$
—
$
350,190
2012
Property
acquisition costs:
Proved properties
$
—
$
—
$
—
Unproved
properties
64,123
—
64,123
Exploration costs
268,153
700
268,853
Development
costs
398,941
182
399,123
Total costs incurred(1)
$
731,217
$
882
$
732,099
2011
Property
acquisition costs:
Proved properties
$
—
$
—
$
—
Unproved
properties
204,484
—
204,484
Exploration costs
286,412
1,003
287,415
Development
costs
417,469
366
417,835
Total costs incurred(1)
$
908,365
$
1,369
$
909,734
____________________________________________
(1)
Includes
amounts relating to changes in estimated asset retirement obligations of $8.6 million, $6.1 million, and $3.1 million recorded during the years ended December 31, 2013, 2012, and 2011, respectively.
106
Results of Operations from Oil and Gas Producing Activities
Results
of operations from oil and gas producing activities for the years ended December 31, 2013, 2012, and 2011 are presented below.
United
States
Italy
Total
(In
Thousands, except per Mcfe amounts)
2013
Oil, natural gas, and natural gas liquids sales
$
441,341
$
—
$
441,341
Expenses:
Production
expense
103,427
—
103,427
Depletion expense
165,767
—
165,767
Ceiling
test write-down of oil and natural gas properties
57,636
—
57,636
Accretion of asset retirement obligations
2,760
74
2,834
Income
tax benefit
(707
)
—
(707
)
Total expenses
328,883
74
328,957
Results
of operations from oil and gas producing activities
$
112,458
$
(74
)
$
112,384
Depletion rate per Mcfe
$
2.20
$
—
$
2.20
2012
Oil,
natural gas, and natural gas liquids sales
$
605,523
$
—
$
605,523
Expenses:
Production
expense
156,909
—
156,909
Depletion expense
275,886
—
275,886
Ceiling
test write-down of oil and natural gas properties
957,587
34,817
992,404
Accretion of asset retirement obligations
6,487
62
6,549
Income
tax expense
173,437
—
173,437
Total expenses
1,570,306
34,879
1,605,185
Results
of operations from oil and gas producing activities
$
(964,783
)
$
(34,879
)
$
(999,662
)
Depletion rate per Mcfe
$
2.28
$
—
$
2.28
2011
Oil,
natural gas, and natural gas liquids sales
$
703,531
$
—
$
703,531
Expenses:
Production
expense
153,518
—
153,518
Depletion expense
213,866
—
213,866
Accretion
of asset retirement obligations
5,973
44
6,017
Income tax expense
89,135
—
89,135
Total
expenses
462,492
44
462,536
Results of operations from oil and gas producing activities
$
241,039
$
(44
)
$
240,995
Depletion
rate per Mcfe
$
1.75
$
—
$
1.75
Standardized Measure of Discounted Future Net Cash Flows
Future
oil, natural gas, and NGL sales are calculated applying the prices used in estimating the Company’s proved oil, natural gas, and NGL reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production
107
and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved reserves at the end of each
year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved reserves, less the tax bases of the properties involved. The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved reserves. All cash flow amounts, including income taxes, are discounted at 10%.
Changes in the demand for oil, natural gas, and NGLs, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the Company’s proved
reserves. Management does not rely upon the information that follows in making investment decisions.
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at beginning of year
$
1,397,097
Changes resulting from:
Sales of oil, natural gas, and NGL net of production costs
(337,914
)
Net
changes in prices and future production costs
222,516
Net changes in future development costs
50,568
Extensions, discoveries, and improved recovery
295,585
Development costs incurred during the period
128,482
Revisions
of previous quantity estimates
(114,712
)
Changes in production rates, timing, and other
19,321
Sales of reserves in place
(1,099,372
)
Purchases of reserves in place
—
Accretion
of discount on reserves at beginning of year
143,432
Net change in income taxes
29,605
Total change for year
(662,489
)
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at end of year
$
734,608
The
computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2013 was based on average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior to December 31, 2013 were $3.67 per MMBtu and $97.33 per barrel, respectively.
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at beginning of year
$
2,285,742
$
101,999
$
2,387,741
Changes
resulting from:
Sales of oil, natural gas, and NGL net of production costs
(448,614
)
—
(448,614
)
Net
changes in prices and future production costs
(1,226,494
)
(9,264
)
(1,235,758
)
Net changes in future development costs
(4,188
)
—
(4,188
)
Extensions,
discoveries, and improved recovery
572,516
—
572,516
Development costs incurred during the period
140,111
—
140,111
Revisions
of previous quantity estimates
(203,987
)
(151,578
)
(355,565
)
Changes in production rates, timing, and other
(34,665
)
—
(34,665
)
Sales
of reserves in place
(213,683
)
—
(213,683
)
Purchases of reserves in place
—
—
—
Accretion
of discount on reserves at beginning of year
259,393
3,923
263,316
Net change in income taxes
270,966
54,920
325,886
Total
change for year
(888,645
)
(101,999
)
(990,644
)
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at end of year
$
1,397,097
$
—
$
1,397,097
The
computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2012 was based on average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior to December 31, 2012 were $2.76 per MMBtu and $94.79 per barrel, respectively.
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at beginning of year
$
1,964,920
$
205,526
$
2,170,446
Changes
resulting from:
Sales of oil, natural gas, and NGL net of production costs
(550,013
)
—
(550,013
)
Net
changes in prices and future production costs
272,027
(153,313
)
118,714
Net changes in future development costs
(55,725
)
(697
)
(56,422
)
Extensions,
discoveries, and improved recovery
667,323
—
667,323
Development costs incurred during the period
231,270
—
231,270
Revisions
of previous quantity estimates
(220,389
)
—
(220,389
)
Changes in production rates, timing, and other
(132,714
)
(40,508
)
(173,222
)
Sales
of reserves in place
(107,742
)
—
(107,742
)
Purchases of reserves in place
—
—
—
Accretion
of discount on reserves at beginning of year
226,354
31,949
258,303
Net change in income taxes
(9,569
)
59,042
49,473
Total
change for year
320,822
(103,527
)
217,295
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at end of year
$
2,285,742
$
101,999
$
2,387,741
110
The computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2011 was based on average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior to December 31, 2011 were $4.12 per MMBtu and $96.08 per barrel, respectively.
111
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Victor A. Wind, evaluated the effectiveness
of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the annual period ended December 31, 2013 (the “Evaluation Date”). Because of the matters discussed below under “Internal Control Issues,” Messrs. McDonald and Wind have concluded that as of the Evaluation Date our disclosure controls and procedures were not effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to Forest’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosures.
Internal Control Issues
Forest’s periodic evaluation of its disclosure controls and procedures includes an assessment of its internal control over financial reporting, which is designed to provide reasonable assurance regarding the reliability of Forest’s financial reporting and the preparation of Forest’s financial statements. In connection with the audit of our year end financial statements, Forest’s independent registered public accounting firm, Ernst & Young LLP (“EY”), is responsible for auditing both (i) the financial statements to obtain reasonable assurance about whether they are free of material misstatement and (ii) the effectiveness of Forest’s internal control over financial reporting.
As
part of management’s assessment, and EY’s audit, of Forest’s internal control over financial reporting as of December 31, 2013, EY or Forest identified certain control deficiencies. Identification of control deficiencies regularly occurs in connection with the assessment or audit of internal control over financial reporting. Control deficiencies exist when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis. A control deficiency may constitute a “significant deficiency” or a “material weakness” as defined in applicable Securities and Exchange Commission (“SEC”) rules. A “significant deficiency” means a deficiency, or a combination of deficiencies, in internal control over financial reporting that is less severe than a material weakness, yet important enough
to merit attention by those responsible for oversight of the registrant’s financial reporting. A “material weakness” means a deficiency or a combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the registrant’s financial statements will not be prevented or detected on a timely basis. However, not all control deficiencies rise to the level of a significant deficiency or a material weakness. Forest management and EY originally concluded that none of the identified control deficiencies constituted a material weakness in Forest’s internal control over financial reporting as of December 31, 2013, and this conclusion was reflected in our Annual Report on Form
10-K for the year ended December 31, 2013, as initially filed on February 26, 2014 (the “Original Filing”).
Subsequent to the filing of the Original Filing, the Public Company Accounting Oversight Board conducted an inspection of EY’s 2013 audits of Forest, and following this inspection, EY requested a reevaluation of the control deficiencies previously identified. In addition, EY and Forest’s management conducted additional analysis of other issues relating to Forest’s internal controls. After extensive consultation with outside experts, management has now concluded that each of the following control deficiencies constituted material weaknesses in Forest’s internal control over financial reporting as of December 31, 2013:
•
Information
technology general controls - User access and program change management general controls were determined to be ineffective. Compensating controls designed by management lacked the level of
112
precision needed and were ineffective because they relied on electronic data from systems with ineffective information technology general controls. Thus Forest’s controls in all areas, some of which were review controls, that relied on electronic data generated from systems with ineffective information technology general controls were inappropriately designed and operating.
•
Division
of interests - Controls over division of interests were determined to be ineffective because changes to Forest’s division of interest master files are not produced in a report that is reviewed by an individual other than the preparer in order to ensure that all changes are appropriate. Further, Forest’s controls were not designed so that changes to the division of interests themselves (as opposed to the master files) would be reviewed by an individual other than the person or persons making the changes. These control deficiencies provided for the opportunity for inappropriate recognition of revenues, operating costs, capital charges, and amounts due to and from third parties as a result of incorrect division of interests.
•
Ceiling
limitation test - Several controls, including review controls, associated with the inputs to the ceiling limitation test (oil and natural gas reserves, unproved properties, capital accrual, asset retirement obligations, and general and administrative cost allocation) lacked sufficient appropriate design or operating precision to prevent reasonably possible errors related to the ceiling limitation test that, when aggregated, could be material.
Accordingly, Forest’s internal control over financial reporting was ineffective at December 31, 2013. In addition, because none of the material weaknesses were adequately remediated as of March 31, 2014 or June 30, 2014, Forest’s internal control over
financial reporting was ineffective at those dates as well. However, Forest has concluded that the existence of these material weaknesses did not result in a material misstatement of Forest’s financial statements included in the Original Filing or in its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 or June 30, 2014, as initially filed on May 6, 2014 and August 18, 2014, respectively.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting,
as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework). Based on our evaluation under the framework in Internal Control-Integrated Framework as described above under “Internal Control Issues,” our management concluded that our internal control over financial reporting was ineffective as of December 31, 2013. The effectiveness of our internal control over financial reporting as of December 31,
2013 has been audited by EY, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control over Financial Reporting
Forest has adopted, and partially implemented, a plan to remediate the material weaknesses described above in “Internal Control Issues.” The implementation of the material aspects of this plan began in the third quarter of 2014. Accordingly, there were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2013 that materially affected, or are likely to materially affect, our internal control over financial reporting.
As
of the date of this filing, the remediation plan consists of the following main elements:
•
Information technology general controls - Forest has implemented controls pursuant to which user access to certain data is reviewed more frequently and developer access to the related software will be limited. These steps have largely been completed.
113
•
Division
of interests - Forest will implement controls that will provide for expanded review and oversight of all changes to its division of interest master files. Forest plans to have this remediation completed by year end.
•
Ceiling limitation test - Forest will implement additional review procedures over the various inputs to the ceiling limitation test. These reviews will occur more frequently and be performed at a more refined level of precision, involving more process owners. Forest plans to have this remediation completed by year end.
We can
give no assurance that the measures we take will remediate the material weaknesses that we have identified or that additional material weaknesses will not arise in the future. We will continue to monitor the effectiveness of these and other processes, procedures, and controls and will make any further changes management determines to be appropriate.
Item 9B. Other Information.
None.
114
Report of Independent Registered Public
Accounting Firm
On Internal Control over Financial Reporting
The Board of Directors and Shareholders of Forest Oil Corporation
We have audited Forest Oil Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Forest Oil Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control
Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.
We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and
that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our report dated February 26, 2014, we expressed an unqualified opinion that Forest Oil Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria. Management has subsequently determined that deficiencies in controls as described in the following paragraph existed as of December 31, 2013, and further concluded that such deficiencies represent material weaknesses as of December 31, 2013. As a result, management has
revised its assessment, as presented in Item 9A. in “Management’s Annual Report on Internal Control Over Financial Reporting”, to conclude that Forest Oil Corporation’s internal control over financial reporting was not effective as of December 31, 2013. Accordingly, our present opinion on the effectiveness of Forest Oil Corporation’s internal control over financial reporting as of December 31, 2013, as expressed herein, is different from that expressed in our previous report.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim
financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment. Management has identified a material weakness related to the design and operation of information technology general controls, specifically user access and program change management. This deficiency impacted controls over the financial statement close process and other review controls relying on electronic data that generally impacted all classes of transactions and thus all significant financial statement accounts. Further, the Company
115
identified
a material weakness related to the design and operating effectiveness of controls over the maintenance of its division of interests, and a material weakness related to the design and operating effectiveness of controls over its oil and gas property ceiling limitation test.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Forest Oil Corporation as of December 31, 2013 and 2012 and the related consolidated statements of operations, comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2013. These material weaknesses were considered in determining the nature, timing
and extent of audit tests applied in our audit of the financial statements and this report does not affect our report dated February 26, 2014, except as it relates to the going concern matter discussed in Note 1, as to which the date is October 1, 2014, which expressed an unqualified opinion that included an explanatory paragraph regarding Forest Oil Corporation’s ability to continue as a going concern.
In our opinion, because of the effects of the material weaknesses described above on the achievement of the objectives of the control criteria, Forest Oil Corporation has not maintained effective control over financial reporting as of December 31, 2013, based on the COSO criteria.
President and Chief Executive Officer since September 2012 after serving as our Interim Chief Executive Officer since June 2012, and has been a member of the Board since 2004. He was appointed as the Chief Executive Officer and as a Director of Carbon Natural Gas Co. in 2011, and continues to serve in such capacities. He also served as Chief Executive Officer, President, and Director of Carbon Natural Gas Co.’s predecessor company, Nytis Exploration Company, since 2004. From 1998 to 2003, Mr. McDonald served as President, Chief Executive Officer, and Director of Carbon
Energy Corporation, an oil and gas exploration and production company. From 1987 to 1997, Mr. McDonald served as Chief Executive Officer, President, and Director of Interenergy Corporation, a natural gas gathering, processing, and marketing company. Prior to that he worked as an exploration geologist with Texaco, Inc. where he was responsible for oil and gas exploration efforts in the Middle and Far East. In March 2011, Mr. McDonald was elected as a director of Lone Pine Resources Inc., an oil and gas exploration, development, and production company.
Victor A. Wind
40
9
Executive
Vice President and Chief Financial Officer since November 2013; Executive Vice President, Chief Financial Officer, and Treasurer from August 2013 until November 2013; Senior Vice President, Chief Accounting Officer, Corporate Controller, and Treasurer since January 2013 until August 2013; Senior Vice President, Chief Accounting Officer, and Corporate Controller from December 2009 until January 2013; Vice President, Chief Accounting Officer, and Corporate Controller from May until December 2009. Mr. Wind joined Forest in January 2005 as our Corporate Controller. Mr. Wind was previously employed by Evergreen Resources, Inc. from July 2001 to December 2004. He served in various management positions during this period, including Director of Financial Reporting and Controller. From 1997 to 2001, he served in various capacities at BDO Seidman, LLP.
Larry C. Busnardo
45
2
Vice
President, Investor Relations since November 2013. Mr. Busnardo joined Forest in April 2012 as Director, Investor Relations. Prior to joining Forest, Mr. Busnardo was with Macquarie Capital (USA) from September 2009 until March 2012, where he served as both an equity research analyst covering the small-cap exploration and production sector and in an energy specialty sales capacity. He served in a similar capacity with Tristone Capital (USA) from February 2007 until its acquisition by Macquarie in September 2009. Prior to that, Mr. Busnardo had 15 years of experience as an equity research analyst and in various investor relations and finance positions working in the exploration and production industry.
Frederick B. Dearman II
56
4
Senior
Vice President, Southern Region since August 2012. Mr. Dearman joined Forest in August 2010 as Managing Director, New Ventures, a role he filled until October 2011, when he was promoted to Vice President of that business unit. Prior to joining Forest, Mr. Dearman served as Special Projects Manager at Apache Corporation, an oil and gas company, from 2001 to 2010. He also held the positions of Corporate Reservoir Engineering Manager from 1998 to 2001 and Senior Staff Reservoir Engineer from 1996 to 1997 at Apache Corporation. He was employed by Amerada Hess Corporation, also an oil and gas company, as a petroleum engineer from 1987 to 1996.
Michael J. Dern
59
13
Senior
Vice President, Corporate Engineering and Technology, since January 2013. Mr. Dern served as Forest’s Vice President, Corporate Engineering, from July 2011 until January 2013, as Manager, Reservoir Engineering, Eastern Region, from May 2005 until July 2011, and as Manager, Corporate Planning, from May 2001 until May 2005. Prior to joining Forest, he had more than 20 years of industry experience in corporate planning, reservoir engineering, and reservoir engineering management at Phillips Petroleum, Exeter Exploration, Midcon Exploration, Apache Corporation, and Gulf Canada Resources.
Timothy F. Savoy
54
12
Senior
Vice President, Mid-Continent Region since December 2013. Mr. Savoy joined Forest in February 2002 as Director Health, Safety, and Environment. In June 2004, he became Vice President, Operations Support and served in that capacity until November 2013, when he was promoted to Senior Vice President, Mid-Continent Region. Mr. Savoy was previously employed by Apache Corporation, an oil and gas exploration and production company, from 1991 to 2001, where he served in various capacities. From 1983 to 1991 he served in various engineering positions at Amoco Production Company.
Richard W. Schelin
68
36
Vice
President, General Counsel, and Secretary since January 2014. Mr. Schelin previously served as Forest’s Deputy General Counsel from October 2000 until his appointment as General Counsel. Prior to joining Forest’s legal department in February 1978, Mr. Schelin was an attorney at the law firm of Moyers, Martin, Conway, Santee & Imel in Tulsa, Oklahoma.
____________________________________________
(1)
Officers are appointed annually at the Board meeting immediately following the annual shareholder meeting, to serve for one-year terms, or until their death, resignation, or removal from office, whichever first occurs.
117
The following information will be included in Forest’s Notice of Annual Meeting of Shareholders and Proxy Statement (the “Proxy Statement”) to be filed with the SEC within 120 days after Forest’s fiscal year end of December 31, 2013 and is incorporated herein by reference:
•
Information concerning Forest’s directors is incorporated by reference to the information under the caption “Proposal No. 1—Election of Directors”
•
Information
concerning the procedures for shareholders of Forest to recommend nominees to the Board is set forth under the caption “Corporate Governance Principles and Information about the Board and its Committees—Consideration of Director Nominees—Shareholder Nominees”
•
Information concerning Forest’s Audit Committee and designated “audit committee financial expert” is set forth under the caption “Corporate Governance Principles and Information about the Board and its Committees—Board Structure; Committee Composition; Meetings”
•
Information
about Forest’s code of ethics for directors, officers, and employees is set forth under the caption “Corporate Governance Principles and Information about the Board and its Committees—Corporate Governance Guidelines and Code of Business Ethics”
•
Information about compliance with Section 16(a) of the Exchange Act is set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance”
Item 11. Executive Compensation.
Information
regarding Forest’s compensation of its named executive officers and directors is set forth under the caption “Executive Compensation” in the Proxy Statement, which information is incorporated herein by reference. See also “Executive Compensation—Compensation Committee Report” and “Corporate Governance Principles and Information about the Board and its Committees—Compensation Committee Interlocks and Insider Participation” for additional information, which information is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information
regarding security ownership of certain beneficial owners, directors, and executive officers is set forth under the caption “Security Ownership of Certain Beneficial Owners and Management” in the Proxy Statement, which information is incorporated herein by reference.
Information regarding Forest’s equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the Proxy Statement, which information is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information
regarding certain relationships and related transactions is set forth under the caption “Transactions with Related Persons, Promoters and Certain Control Persons,” and information regarding director independence is set forth under the caption “Corporate Governance Principles and Information about the Board and its Committees—Board Independence” in the Proxy Statement, which information is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services.
Information regarding principal accounting fees and services is set forth under the caption “Principal Accountant Fees and Services” in the Proxy Statement, which information is incorporated
herein by reference.
Consolidated
Statements of Operations—Years Ended December 31, 2013, 2012, and 2011
4.
Consolidated Statements of Comprehensive Income—Years Ended December 31, 2013, 2012, and 2011
5.
Consolidated
Statements of Shareholders’ Equity—Years Ended December 31, 2013, 2012, and 2011
6.
Consolidated Statements of Cash Flows—Years Ended December 31, 2013, 2012, and 2011
7.
Notes
to Consolidated Financial Statements—Years Ended December 31, 2013, 2012, and 2011
(2)
Financial Statement Schedules: All schedules have been omitted because the information is either not required or is set forth in the financial statements or the notes thereto.
(3)
Exhibits:
See the Index of Exhibits in Item 15(b) hereof for a list of those exhibits filed as part of this Annual Report on Form 10-K.
Second
Amended and Restated Credit Agreement dated as of June 6, 2007 among Forest Oil Corporation, each of the lenders that is party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas, BMO Capital Markets Financing, Inc., Credit Suisse, Cayman Islands Branch, and Deutsche Bank Securities, Inc., as Co-U.S. Documentation Agents, and JPMorgan Chase Bank, N.A., as Global Administrative Agent, incorporated herein by reference to Exhibit 4.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
4.8
First
Amendment dated May 9, 2008 to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and JPMorgan Chase Bank N.A., Toronto Branch, as Canadian Administrative Agent, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 9, 2008 (File No. 001-13515).
4.9
Second
Amendment dated March 16, 2009, to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders that is party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and JPMorgan Chase Bank, N.A., Toronto Branch, as Canadian Administrative Agent, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation dated March 16, 2009 (File No. 001-13515).
120
Exhibit
Number
Description
4.10
Third
Amendment to Second Amended and Restated U.S. Credit Agreement and Termination of Second Amended and Restated Canadian Credit Agreement, dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., JPMorgan Chase Bank, N.A., Toronto branch, as Canadian Administrative Agent, JPMorgan Chase Bank, N.A., as global administrative agent, and the Lenders named therein, incorporated by reference to Exhibit 4.1 to Form 8-K to Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).
4.11
Third
Amended and Restated Credit Agreement, dated as of June 30, 2011, among Forest Oil Corporation, the Lenders party thereto, BNP Paribas and Wells Fargo Bank, N.A., as Co-Syndication Agents, Bank of America, N.A., The Bank of Nova Scotia, Credit Suisse AG, Cayman Islands branch, Deutsche Bank Securities, Inc. and Toronto Dominion (Texas) LLC, as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed July 6, 2011 (File No. 001-13515).
4.12
First
Amendment to Third Amended and Restated Credit Agreement, dated as of September 12, 2013, among Forest Oil Corporation, the lenders signatory thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed September 18, 2013 (File No. 001-13515).
Amendment No. 1 to Forest Oil Corporation’s 2001 Stock Incentive Plan, incorporated
herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2003 (File No. 001-13515).
Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
10.11
*
Form
of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, as amended, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
121
Exhibit
Number
Description
10.12
*
Forest
Oil Corporation 2007 Stock Incentive Plan, incorporated by reference to Annex E to Registration Statement on Form S-4 for Forest Oil Corporation, dated April 30, 2007 (File No. 333-140532).
10.13
*
Amendment No. 1 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated
by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).
Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to
Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
10.19
*
Form of Non-Employee Director Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest
Oil Corporation for the quarter ended March 31, 2008 (File No. 001-13515).
10.20
*
Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30,
2008 (File No. 001-13515).
Form
of CEO Restricted Stock Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).
10.23
*
Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil
Corporation 2007 Stock Incentive Plan - Cliff Vest, incorporated herein by reference to Exhibit 10.22 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
10.24
*
Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan
- One-Third Vest, incorporated herein by reference to Exhibit 10.23 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
Form
of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).
10.28
*
Form of Non-Employee Director Phantom Stock Unit Agreement
pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated by reference to Exhibit 10.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).
10.29
*
Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive
Plan, as amended, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2009 (File No. 001-13515).
10.30
*
Form of Phantom Stock Unit Agreement (Cash Only Three Vesting Tranches) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan,
as amended, incorporated by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2011 (File No. 001-13515).
10.31
*
Form of Phantom Stock Unit Agreement (4-Year Pro-Rated Vesting) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated
herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed November 14, 2012 (File No. 001-13515).
10.32
*
Form of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - Cliff Vest, incorporated by reference to Exhibit 10.29 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
10.33
*
Form
of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - One-Third Vest, incorporated by reference to Exhibit 10.30 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
Form of Performance Unit Award Agreement (US) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated herein
by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 21, 2010 (File No. 001-13515).
10.37
*
Form of Forest Oil Corporation Performance Unit Award Agreement - 2012, pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated by reference to Exhibit 10.1
to Form 8-K for Forest Oil Corporation filed March 16, 2012 (File No. 001-13515).
10.38
*
Form of CEO Plan Performance Unit Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated herein by reference to Exhibit 10.2 to Form 8-K to Forest Oil Corporation filed
October 1, 2012 (File No. 001-13515).
Form of Amendment to Form of Severance Agreement for Grandfathered Executive Officer, incorporated herein by reference to Exhibit 10.30 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2008 (File No. 001-13515).
10.47
*
Form
of 409A Amendment to Severance Agreement for Grandfathered Vice President and Senior Vice President – No 5-Day Release Provision, incorporated herein by reference to Exhibit 10.6 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2012 (File No. 001-13515).
Second Amendment to Forest Oil Corporation Executive Deferred
Compensation Plan (as Amended and Restated, effective as of December 1, 2008), incorporated by reference to Exhibit 10.50 to form 10-K for Forest Oil Corporation for the fiscal year ended December 31, 2011 (File No. 001-13515).
Separation and Distribution Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed June
1, 2011 (File No. 001-13515).
10.64
Transition Services Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed June 1, 2011
(File No. 001-13515).
Employee
Matters Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).
Share
Purchase and Sale Agreement, effective as of March 31, 2012, by and among African International Energy PLC, Forest Oil Corporation, Anschutz South Africa Corporation, Forest Exploration International (South Africa) (Proprietary) Ltd and Anschutz Overseas (South Africa) (Proprietary) ltd, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 13, 2012 (File No. 001-13515).
10.70
Share
Purchase and Sale Agreement, effective as of March 31, 2012, by and between African International Energy PLC and Forest Oil Netherlands BV, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 13, 2012 (File No. 001-13515).
10.71
Agreement
for Purchase and Sale of Assets, dated as of October 11, 2012, by and between Forest Oil Corporation and Texas Petroleum Investment Company, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001.13515).
10.72
Agreement, dated as of October
22, 2012, by and among Forest Oil Corporation, Richard J. Carty, West Face Capital Inc. and West Face Long Term Opportunities Global Market L.P., incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 24, 2012 (File No. 001-13515).
Agreement for Purchase and Sale
of Assets, dated as of January 2, 2012, by and between Forest Oil Corporation, Forest Oil Permian Corporation, and Forcenergy Onshore Inc. (as Seller) and Hilcorp Energy I, L.P. (as Purchaser), incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed January 3, 2012 (File No. 001-13515).
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 (File No. 001-13515).
Agreement
for Purchase and Sale of Assets, dated as of October 3, 2013, by and between Forest Oil Corporation, Forest Oil Permian Corporation, and Templar Energy LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 4, 2013 (File No. 001-13515).
21.1
List
of Subsidiaries of Registrant, filed with the Original Filing.
Power of Attorney (included on the signature pages of the Original Filing).
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 Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
32.2
**
Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
99.1
Reserves
Audit Report of DeGolyer and MacNaughton, independent petroleum engineering consulting firm, dated January 24, 2014, filed with the Original Filing.
*Contract or compensatory plan or arrangement in which directors and/or officers participate.
**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.
†Indicates Exhibits filed with this Form 10-K/A.
±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 of 1933, are deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise, are not subject to liability under these sections.
126
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Second
Amended and Restated Credit Agreement dated as of June 6, 2007 among Forest Oil Corporation, each of the lenders that is party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas, BMO Capital Markets Financing, Inc., Credit Suisse, Cayman Islands Branch, and Deutsche Bank Securities, Inc., as Co-U.S. Documentation Agents, and JPMorgan Chase Bank, N.A., as Global Administrative Agent, incorporated herein by reference to Exhibit 4.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
4.8
First
Amendment dated May 9, 2008 to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and JPMorgan Chase Bank N.A., Toronto Branch, as Canadian Administrative Agent, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 9, 2008 (File No. 001-13515).
4.9
Second
Amendment dated March 16, 2009, to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders that is party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and JPMorgan Chase Bank, N.A., Toronto Branch, as Canadian Administrative Agent, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation dated March 16, 2009 (File No. 001-13515).
128
Exhibit
Number
Description
4.10
Third
Amendment to Second Amended and Restated U.S. Credit Agreement and Termination of Second Amended and Restated Canadian Credit Agreement, dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., JPMorgan Chase Bank, N.A., Toronto branch, as Canadian Administrative Agent, JPMorgan Chase Bank, N.A., as global administrative agent, and the Lenders named therein, incorporated by reference to Exhibit 4.1 to Form 8-K to Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).
4.11
Third
Amended and Restated Credit Agreement, dated as of June 30, 2011, among Forest Oil Corporation, the Lenders party thereto, BNP Paribas and Wells Fargo Bank, N.A., as Co-Syndication Agents, Bank of America, N.A., The Bank of Nova Scotia, Credit Suisse AG, Cayman Islands branch, Deutsche Bank Securities, Inc. and Toronto Dominion (Texas) LLC, as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed July 6, 2011 (File No. 001-13515).
4.12
First
Amendment to Third Amended and Restated Credit Agreement, dated as of September 12, 2013, among Forest Oil Corporation, the lenders signatory thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed September 18, 2013 (File No. 001-13515).
Amendment No. 1 to Forest Oil Corporation’s 2001 Stock Incentive Plan, incorporated
herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2003 (File No. 001-13515).
Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
10.11
*
Form
of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, as amended, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
Amendment No. 1 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated
by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).
Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to
Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).
10.19
*
Form of Non-Employee Director Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest
Oil Corporation for the quarter ended March 31, 2008 (File No. 001-13515).
10.20
*
Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30,
2008 (File No. 001-13515).
Form
of CEO Restricted Stock Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).
10.23
*
Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil
Corporation 2007 Stock Incentive Plan - Cliff Vest, incorporated herein by reference to Exhibit 10.22 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
10.24
*
Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan
- One-Third Vest, incorporated herein by reference to Exhibit 10.23 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
Form
of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).
10.28
*
Form of Non-Employee Director Phantom Stock Unit Agreement
pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated by reference to Exhibit 10.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).
10.29
*
Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive
Plan, as amended, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2009 (File No. 001-13515).
10.30
*
Form of Phantom Stock Unit Agreement (Cash Only Three Vesting Tranches) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan,
as amended, incorporated by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2011 (File No. 001-13515).
10.31
*
Form of Phantom Stock Unit Agreement (4-Year Pro-Rated Vesting) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated
herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed November 14, 2012 (File No. 001-13515).
10.32
*
Form of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - Cliff Vest, incorporated by reference to Exhibit 10.29 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
10.33
*
Form
of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - One-Third Vest, incorporated by reference to Exhibit 10.30 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2012 (File No. 001-13515).
Form of Performance Unit Award Agreement (US) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated herein
by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 21, 2010 (File No. 001-13515).
10.37
*
Form of Forest Oil Corporation Performance Unit Award Agreement - 2012, pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated by reference to Exhibit 10.1
to Form 8-K for Forest Oil Corporation filed March 16, 2012 (File No. 001-13515).
10.38
*
Form of CEO Plan Performance Unit Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated herein by reference to Exhibit 10.2 to Form 8-K to Forest Oil Corporation filed
October 1, 2012 (File No. 001-13515).
Form of Amendment to Form of Severance Agreement for Grandfathered Executive Officer, incorporated herein by reference to Exhibit 10.30 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2008 (File No. 001-13515).
10.47
*
Form
of 409A Amendment to Severance Agreement for Grandfathered Vice President and Senior Vice President – No 5-Day Release Provision, incorporated herein by reference to Exhibit 10.6 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2012 (File No. 001-13515).
Second Amendment to Forest Oil Corporation Executive Deferred
Compensation Plan (as Amended and Restated, effective as of December 1, 2008), incorporated by reference to Exhibit 10.50 to form 10-K for Forest Oil Corporation for the fiscal year ended December 31, 2011 (File No. 001-13515).
Separation and Distribution Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed June
1, 2011 (File No. 001-13515).
10.64
Transition Services Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed June 1, 2011
(File No. 001-13515).
Employee
Matters Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).
Share
Purchase and Sale Agreement, effective as of March 31, 2012, by and among African International Energy PLC, Forest Oil Corporation, Anschutz South Africa Corporation, Forest Exploration International (South Africa) (Proprietary) Ltd and Anschutz Overseas (South Africa) (Proprietary) ltd, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed April 13, 2012 (File No. 001-13515).
10.70
Share
Purchase and Sale Agreement, effective as of March 31, 2012, by and between African International Energy PLC and Forest Oil Netherlands BV, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 13, 2012 (File No. 001-13515).
10.71
Agreement
for Purchase and Sale of Assets, dated as of October 11, 2012, by and between Forest Oil Corporation and Texas Petroleum Investment Company, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001.13515).
10.72
Agreement, dated as of October
22, 2012, by and among Forest Oil Corporation, Richard J. Carty, West Face Capital Inc. and West Face Long Term Opportunities Global Market L.P., incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 24, 2012 (File No. 001-13515).
Agreement for Purchase and Sale
of Assets, dated as of January 2, 2012, by and between Forest Oil Corporation, Forest Oil Permian Corporation, and Forcenergy Onshore Inc. (as Seller) and Hilcorp Energy I, L.P. (as Purchaser), incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed January 3, 2012 (File No. 001-13515).
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 (File No. 001-13515).
Agreement
for Purchase and Sale of Assets, dated as of October 3, 2013, by and between Forest Oil Corporation, Forest Oil Permian Corporation, and Templar Energy LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 4, 2013 (File No. 001-13515).
21.1
List
of Subsidiaries of Registrant, filed with the Original Filing.
Power of Attorney (included on the signature pages of the Original Filing).
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 Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
32.2
**
Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
99.1
Reserves
Audit Report of DeGolyer and MacNaughton, independent petroleum engineering consulting firm, dated January 24, 2014, filed with the Original Filing.
*Contract or compensatory plan or arrangement in which directors and/or officers participate.
**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.
†Indicates Exhibits filed with this Form 10-K/A.
±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 of 1933, are deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise, are not subject to liability under these sections.
134
Dates Referenced Herein and Documents Incorporated by Reference
