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 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, 2011 were approximately 1,904 Bcfe. At December 31, 2011, approximately 97% of Forest's estimated proved oil and gas reserves were in the United States.
In June 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 of record as of September 16, 2011, by means of a special stock dividend of Lone Pine common shares. As a result of the spin-off, Lone Pine is reported as a discontinued operation throughout this Form 10-K. See "Acquisition and Divestiture Activities" below for more information on the initial public offering and subsequent spin-off of Lone Pine.
Strategy
Following the spin-off of Lone Pine, Forest implemented a long-term operating strategy intended to increase shareholder value through the achievement of organic production and reserve growth while maintaining a capital expenditure budget that approximates cash flow from operating activities. Forest believes measured growth can be achieved through this strategy by focusing capital expenditures primarily on developing Forest’s core operational areas located in the Texas Panhandle, East Texas / North Louisiana, and in the Eagle Ford Shale in South Texas. In addition, our growth may be supplemented from time to time through opportunistic acquisitions. We endeavor to execute this strategy as follows:
Exploit and develop resource plays for measured production and reserve growth while maintaining a capital expenditure budget that approximates cash flow from operating activities. In our efforts to grow production and reserves, we plan to continue to apply the latest technologies to our resource plays, including horizontal drilling and multi-stage hydraulic fracture stimulation techniques. We believe these technologies provide for efficient production and reserve growth from our diverse portfolio of shale and conventional oil and gas acreage positions. Our core operational areas have a large number of remaining commodity-diverse drilling locations, providing what we believe to be are repeatable development opportunities. In 2012, due to a low natural gas price environment, we intend to devote the majority of our exploration and development expenditures to oil and liquids projects, including approximately 50% in the Texas Panhandle where liquids-rich Granite Wash and shallow oil intervals are targeted. Further, due to the low natural gas price environment, we expect our capital expenditures will exceed our cash flows in 2012.
Focus on operational control, cost efficiencies, and high-margin projects. Our development efforts are focused in areas where we have concentrated land positions, a large drilling inventory, and operational control, which allow us to optimize our development plans and, therefore, reduce costs. Furthermore, our diverse portfolio allows us to allocate capital to projects with the highest margins, which currently include oil or liquids-rich drilling prospects. Our concentrated land positions, operational control, and focus on cost and margin allow us to achieve economies of scale and potentially provide for higher rates of return on invested capital.
Rationalize our asset base through leasehold and property acquisitions, divestitures, and exploration. We intend to pursue leasehold and property acquisitions to enhance existing business operations in our core operational areas and in new areas emphasizing grass roots leasing efforts at attractive entry cost, with a preference for liquids-rich hydrocarbon prospects. We also plan to pursue a measured exploration program in these areas through the utilization of our strong internal technical staff. As economic conditions permit, we intend to divest assets that do not fit our primary business strategy, including those without significant development opportunities.
Maintain financial flexibility. We intend to maintain a strong liquidity position to successfully execute our growth strategy through the application of budget controls and prudent financial management. Further, we intend to focus on reducing our debt levels relative to our estimated proved reserves and EBITDA and will consider joint ventures, divestitures, and other means to increase our financial flexibility.
Core Operational Areas
Forest's core areas consist of a well-balanced portfolio of tight-gas sands, carbonates, and shale plays with multiple stacked-pay opportunities in the United States that have exposure to oil, natural gas liquids, and natural gas. Initial vertical delineation drilling in many of our core areas has established the existence of consistent geologic trends, creating what we believe to be low-risk, repeatable development opportunities. Forest initially exploited the majority of its core operational areas through vertical development, but with the emergence of new drilling and completion technology, Forest has transitioned the development of a number of these plays to horizontal development. Through the application of horizontal drilling, Forest seeks to enhance initial production rates and estimated ultimate recoveries while focusing on reducing drilling costs. Our primary areas of focus in 2012 will be in the Texas Panhandle, East Texas / North Louisiana, and in the Eagle Ford Shale in South Texas.
Texas Panhandle
We have approximately 109,000 net acres in the Texas Panhandle, establishing Forest as one of the top acreage holders in this area. The area provides for excellent horizontal drilling opportunities targeting multiple liquids-rich Granite Wash intervals as well as oil-rich objectives including the Tonkawa, Cleveland, and Missourian Wash formations. We drilled our first horizontal wells in the area in 2009, leveraging our vertical delineation database of over 600 wells to determine the most attractive intervals to initiate a horizontal drilling campaign. Based on significant results achieved through the 2009 horizontal drilling program, Forest increased its horizontal development rig count from one to five rigs from 2009 to 2010, developing known productive intervals and establishing new prospective intervals for future drilling efforts. In total, Forest has successfully tested seven liquids-rich intervals as prospective for horizontal development in the Granite Wash. With the favorable price of condensate and natural gas liquids relative to natural gas, this liquids-rich play provides superior rates of return compared to other natural gas plays in North America. Additionally, during 2011, Forest successfully tested two prospective oil intervals, including the shallow Cleveland formation and the Missourian Wash (Hogshooter) formation, that expands the oil drilling potential within the Texas Panhandle. In total, Forest has tested 11 intervals as prospective for horizontal development in the Texas Panhandle. In 2012, we plan to run a five to six rig drilling program targeting the Granite Wash and other prospective intervals, including the Cleveland and Missourian Wash formations.
East Texas / North Louisiana
We have approximately 125,000 net acres in the East Texas / North Louisiana area. The area provides for both horizontal and vertical drilling opportunities targeting multiple stacked-pay intervals, including the Cotton Valley, Haynesville, Pettit, and other formations. In 2010, our development program was focused in the Haynesville/Bossier Shale in North Louisiana where we drilled 20 horizontal wells that had average 24-hour initial production rates of 16 MMcfe/d. In an effort to optimize recovery from Haynesville/Bossier Shale wells, Forest instituted a restricted flow rate production program in late-2010. Under this program, initial production rates from the last six wells were curtailed at 11 to 15 MMcfe/d. In 2011, Forest reduced drilling and completions efforts in the Haynesville/Bossier Shale in North Louisiana and the Cotton Valley in East Texas due to increasing service costs. By the end of 2011, Forest re-entered the plays as a result of reductions in drilling and completion costs in the region, positive performance from its restricted rate production program in the Haynesville/Bossier Shale, and liquids-rich drilling opportunities in the Cotton Valley. In 2012, we plan to run a two rig drilling program in North Louisiana and East Texas.
South Texas-Eagle Ford Shale
We have approximately 103,000 net acres in the Eagle Ford Shale, primarily located in Gonzales County in South Texas. The area provides Forest with access to the oil-bearing section of the Eagle Ford and is expected to yield an oil development opportunity through the application of horizontal drilling and completion technologies. We commenced the drilling of our first horizontal well in the Eagle Ford oil window at the end of 2010 and expanded the program in 2011 to focus on the optimization of our development operations. This optimization included taking core samples, acquiring 3-D seismic, the utilization of micro-seismic during horizontal well completions, and testing different sections of the Eagle Ford Shale, all with the goal of finding the optimal section in the Eagle Ford in which to land the lateral and the most effective and efficient methods to complete the wells. Through Forest's optimization efforts undertaken in 2011 in the Eagle Ford Shale, we believe that we can ultimately generate economic production rates and recoveries. In 2012, we plan to run a one rig drilling program in the Eagle Ford Shale.
Acquisition and Divestiture Activities
We pursue acquisitions that meet our criteria for investment returns and are consistent with our North American onshore low-risk development focus, and we pursue divestitures of non-core assets to upgrade our portfolio and further increase our operational efficiencies. Acquisitions in and around our existing core areas enable us to leverage our cost control abilities, technical expertise, and existing land and infrastructure positions. In general, our acquisition program has focused on acquisitions of properties that have substantial development drilling opportunities and undeveloped acreage positions. The following sets forth our significant acquisitions and divestitures over the last several years.
Acquisitions
During 2011 and early 2012, we acquired 126,000 gross acres (114,500 net) prospective for oil production in the Permian Basin. The acreage position was established in areas prospective for both the Wolfcamp Shale in Crockett County, Texas, where Forest has 57,500 gross acres (51,500 net) and the Wolfbone zones in Pecos and Reeves Counties, Texas, where Forest has 68,500 gross acres (63,000 net). We believe this acreage position allows us access to significant oil drilling opportunities that we intend to pursue in 2012.
In September 2008, we acquired producing oil and natural gas properties located in our Texas Panhandle and East Texas / North Louisiana core areas from Cordillera Texas, L.P. for approximately $570 million in cash and 7.25 million shares of our common stock, valued at approximately $360 million. As of the closing date of the acquisition, the assets included approximately 350 Bcfe of estimated proved reserves and 85,000 net acres.
In June 2007, we acquired The Houston Exploration Company ("Houston Exploration") in a cash and stock transaction totaling approximately $1.5 billion including the assumption of Houston Exploration's debt. Houston Exploration was an independent natural gas and oil producer engaged in the exploration, development, and acquisition of natural gas and oil reserves in North America. At the time of the acquisition, we estimated the Houston Exploration proved reserves to be 653 Bcfe. Pursuant to the terms and conditions of the agreement and plan of merger, Forest paid total merger consideration of $750 million in cash and issued approximately 24 million shares of our common stock, valued at approximately $726 million.
Divestitures
In December 2010, Forest announced its intention to separate its Canadian operations through an initial public offering of up to 19.9% of the common stock of its wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which would hold Forest’s ownership interests in its Canadian operations, followed by a distribution, or spin-off, of the remaining shares of Lone Pine to Forest's shareholders. The initial public offering of Lone Pine occurred in June 2011, with Forest retaining approximately 82% of the outstanding shares of Lone Pine's common stock. Lone Pine used the net proceeds from the offering, along with borrowings under its credit facility, to pay approximately $29 million to Forest, as partial consideration for the contribution to Lone Pine of Forest’s interests in the Canadian operations, and to repay an intercompany note and intercompany advances and accrued interest of approximately $401 million. The spin-off of Forest's remaining shares of Lone Pine to Forest shareholders was completed on September 30, 2011.
In 2009, we sold all of our oil and gas properties located in the Permian Basin in West Texas and New Mexico as well as other oil and gas properties in the U.S. for approximately $933 million in cash. We estimated the proved reserves associated with these properties were 551 Bcfe at the closings of the relevant transactions.
In August 2007, we sold all of our assets located in Alaska to Pacific Energy Resources Ltd. ("PERL"), with such assets estimated to have proved reserves of 173 Bcfe at the time of closing. Total consideration received for the assets included $400 million in cash as well as 10 million shares of PERL common stock and a zero coupon senior subordinated note from PERL due 2014 at a principal amount of $61 million.
In March 2006, we completed a spin-off of our offshore Gulf of Mexico operations by means of a special dividend, which consisted of a pro rata spin-off of all outstanding shares of a Forest subsidiary that held our offshore Gulf of Mexico assets, to holders of record of Forest common stock as of the close of business on February 21, 2006. Immediately following the spin-off, the Forest subsidiary was merged with a subsidiary of Mariner Energy, Inc. ("Mariner"), at which time the 50.6 million shares included in the spin-off were exchanged for an equal number of Mariner common shares. Mariner's common stock commenced trading on the New York Stock Exchange ("NYSE") on March 3, 2006. We estimated the proved reserves associated with the spin-off to be 313 Bcfe at the time of closing.
Reserves
The following table summarizes our estimated quantities of proved reserves as of December 31, 2011, based on the Henry Hub price of $4.12 per MMBtu for natural gas and the West Texas Intermediate price of $96.08 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, 2011. See-"Preparation of Reserves Estimates" below and Note 15 to the Consolidated Financial Statements for additional information regarding our estimated proved reserves.
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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 2011, the average of the first-day-of-the-month gas price was $4.12 per Mcf, and the average of the first-day-of-the-month oil price was $96.08 per barrel. If a price-equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 23 Mcf per barrel of oil and approximately 13 Mcf per barrel of NGLs (based on the average of the first-day-of-the-month Mt. Belvieu pricing for NGLs in 2011).
As of December 31, 2011, Forest had estimated proved reserves of 1,904 Bcfe, an increase of 2% compared to 1,868 Bcfe of estimated proved reserves from continuing operations at December 31, 2010. Of the December 31, 2011 total, 1,853 Bcfe (97%) were in the United States and 52 Bcfe (3%) were in Italy. During 2011, we added 301 Bcfe of estimated proved reserves through extensions and discoveries primarily driven by our 2011 drilling activity in the Texas Panhandle and South Texas, with such additions partially offset by property sales of 21 Bcfe and negative revisions of 120 Bcfe, including 47 Bcfe related to proved undeveloped locations ("PUD") that were written off pursuant to the Securities and Exchange Commission's ("SEC") five year development limitation on PUDs.
As of December 31, 2011, proved undeveloped reserves were estimated to be 866 Bcfe, or 45% of estimated proved reserves, compared to 730 Bcfe, or 39% of estimated proved reserves from continuing operations as of December 31, 2010. The net increase of 136 Bcfe was primarily due to the recording of horizontal PUDs in the Texas Panhandle and South Texas. We invested $182 million to convert 71 Bcfe of our December 31, 2010 PUD reserves to proved developed reserves during 2011. We have no material concentrations of PUDs in individual fields or countries that we expect to remain undeveloped for five years past the date they were initially disclosed as PUDs, except with respect to a concentration of reserves in Italy related to four natural gas wells (which make up all of the 52 Bcfe of proved reserves in Italy).
In 2007, we drilled, completed, and tested two natural gas wells in Italy. At December 31, 2007, we recorded proved developed reserves attributable to those two wells as well as proved undeveloped reserves attributable to two undrilled offset locations. Since 2007, we have been engaged with various governmental and jurisdictional agencies in a process to obtain approval of an environmental impact assessment (“EIA”) and a production license needed to initiate production from the developed reserves, and to start full field development. The process has proceeded at a considerably slower pace than we anticipated and has still not reached a conclusion. At December 31, 2011, we determined to reclassify our proved developed reserves associated with the two wells already drilled and completed in Italy to the proved undeveloped category. At the present time, we anticipate obtaining approval of the EIA and production license during 2012. If we are successful in that respect, we would expect to initiate production in Italy in early 2015, following the construction of a needed desulfurization plant and pipeline. During the initial two years of production, the volumes that we may produce in Italy under the anticipated regulatory conditions will be limited to approximately 12 MMcf/day. This curtailment, coupled with the expected plant capacity, will likely cause us to delay drilling the two undeveloped locations until 2017.
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, 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 Vice President, Corporate Engineering, 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 Vice President, Corporate Engineering, Michael Dern, has 34 years of experience in oil and gas exploration and production and has held this position at Forest since July 2011. Prior to that time, Mr. Dern held positions of increasing responsibility at Forest since joining the company in 2001, including most recently Reservoir Engineering Manager for the Eastern Region. Prior to joining Forest, Mr. Dern held various positions in reservoir engineering and corporate planning with Phillips Petroleum, Midcon Exploration, and Apache Corporation. Mr. Dern received a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines.
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
Item 1A. Risk Factors.
We are subject to certain risks and hazards due to the nature of the business activities we conduct, including the risks discussed below. 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.
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 76% of our estimated proved reserves at December 31, 2011 were natural gas, causing us to be particularly dependent on prices for natural gas.
During the fourth quarter of 2011 and continuing into 2012, natural gas prices declined to ten year lows. Further deterioration in prices may mean that it will not be economical to drill or produce 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 continuation of low natural gas prices, or a significant decline in oil prices, may have the following effects on our business:
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impairing our financial condition, liquidity, or ability to fund planned capital expenditures;
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limiting our access to sources of capital, such as equity and debt; or
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prohibiting us from developing our current properties, or from growing our asset base.
We have substantial indebtedness, and we may incur more debt in the future. Our leverage may materially affect our operations and financial condition.
As of December 31, 2011, we had long-term indebtedness of $1.7 billion, including $105 million drawn under our bank
credit facility. The governing documents of our debt contain covenants and restrictions that require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness.
Our level of debt may have several important effects on our business and operations; among other things, it may:
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require us to use a significant portion of our cash flow 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;
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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;
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limit our access to the capital markets;
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increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;
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place us at a disadvantage compared to companies in our industry that have less debt and other financial obligations; and
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make us more vulnerable to economic downturns, volatile oil and natural gas prices, and adverse developments in our business.
If our cash flow is not sufficient to service our debt and other obligations or to meet the financial covenants, we may be required to refinance the debt, sell assets, or sell shares of our stock-all on terms that we do not find attractive, if it can be done at all.
We are a relatively small company and therefore may not be able to compete effectively.
Compared to many of the companies in our industry, we are a small company. We face difficulties in competing with the 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. Our limited size can place us at a disadvantage with respect to funding such costs. Our limited size also 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. Our size can also impair our ability to attract and retain staff and maintain competitive technical capabilities.
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 contained in this report 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 and natural gas 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, 2011, approximately 45% 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.
You should not assume that any present value of future net cash flows from our estimated proved reserves represents the market value of our oil and natural gas reserves.
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.
Most 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.
A sizable portion of our acreage 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 for these areas 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.
The marketability of our production is dependent upon 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. 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 cash flow.
Drilling is a high-risk activity that could result in substantial losses for us.
We conduct a portion of our drilling activities through a wholly-owned drilling subsidiary that operates drilling rigs and provides services to us and third parties. The activities conducted by the drilling subsidiary 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 NGL 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 had the hedge not been in place.
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 had we elected to use hedge accounting. As a consequence, we may report material unrealized losses or gains on our hedging agreements prior to their expiry. The amount of the actual 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.
The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted by Congress is expected to, among other things, impose new requirements and oversight on derivatives transactions, including new clearing and margin requirements. While implementing regulations are yet to be completed by federal regulatory agencies, to the extent they are applicable to us or our derivatives counterparties, we may incur increased costs and cash collateral requirements that could affect our ability effectively 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. 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. 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.
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 Consolidated Financial Statements for a more complete discussion of credit risk with respect to our derivative instruments.
We may record impairments of our asset values, which could negatively affect our results of operations and net worth.
We follow the full cost method of accounting for our oil and natural gas properties. Depending upon the twelve-month average oil and natural gas prices at the end of each quarterly and annual period when we are required to test the carrying value of our assets using full cost accounting rules, we may be required to write-down the value of our oil and natural gas properties if the present value of the after-tax future cash flows, adjusted as required, from our oil and natural gas properties falls below the net book value of these properties, adjusted as required. Such write-downs are referred to as “ceiling test write-downs.” We have in the past experienced ceiling test write-downs with respect to our oil and natural gas properties. Future non-cash ceiling test write-downs could negatively affect our results of operations and net worth. See Part II, Item 7 - “Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies, Estimates, Judgments, and Assumptions-Full Cost Method of Accounting.”
We also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting unit exceeds the estimated fair value of that reporting unit, an impairment charge will occur, which would negatively impact our results of operations and net worth. See Part II, Item 7 - “Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies, Estimates, Judgments, and Assumptions-Goodwill.”
We may face liabilities related to the pending bankruptcy of Pacific Energy Resources, Ltd.
In August 2007, we closed on the sale of our oil and gas assets in Alaska (the "Alaska Assets") to Pacific Energy Resources, Ltd. ("PERL"). In March 2009, PERL filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. PERL requested, and the bankruptcy court has approved, abandonment of PERL's interests in certain of the Alaska Assets. The remaining working interest owners in the Alaska Assets have made the assertion that, in its role as assignor of the Alaska Assets, Forest should be held liable for any contractual obligations of PERL with respect to the Alaska Assets, including obligations related to operating costs and for costs associated with the final plugging and decommissioning of wells and production facilities. For example, Forest has been joined as a defendant in a dispute over which companies should bear the cost of decommissioning and abandoning a platform and its associated wells, located in Cook Inlet, Alaska. See Part I, Item 3 - "Legal Proceedings" for a discussion of material litigation involving the Alaska Assets.
Item 1B.
Item 1B. Unresolved Staff Comments.
As of January 25, 2012, all SEC staff comments regarding our periodic or current reports that had been received prior to 180 days before December 31, 2011 had been resolved.
Item 2.
Item 2. Properties.
Information on Properties is contained in Item 1 of this Annual Report on Form 10-K.
Item 3.
Item 3. Legal Proceedings.
In August 2007, Forest sold all of its Alaska assets to Pacific Energy Resources Ltd. and its related entities ("PERL"). On March 9, 2009, PERL filed for bankruptcy. As part of the plan of liquidation of its bankruptcy, PERL "abandoned" its interests in many of the Alaska assets sold to it by Forest, including the Trading Bay Unit and Trading Bay Field ("Trading Bay"). At the time of the abandonment of PERL's interests in Trading Bay, Union Oil Company of California ("Unocal") was the operator of those assets. On December 2, 2010, Unocal filed a lawsuit styled Union Oil Company of California v. Forest Oil Corporation in Anchorage District Court, Alaska. Forest has removed the case to federal district court in Anchorage, Alaska. In the lawsuit, the plaintiff complains about PERL's abandonment of Trading Bay and states that PERL has failed to pay approximately $48 million in joint interest billings owed on those properties to date from the time PERL owned them. The plaintiff further claims that Forest is liable for PERL's share of all joint interest billings owed on Trading Bay, in arrears and in the future, because (1) Forest was the predecessor party to the contracts governing the operations at Trading Bay, (2) Unocal did not agree that, in conjunction with Forest's sale of its Alaska assets, Forest would be released of its obligations under the Trading Bay contracts, and (3) PERL has defaulted on the joint interest billings owed on Trading Bay since October 2008. As of December 31, 2011, Unocal sold its interest in the Trading Bay assets, including its claims against Forest, to Hilcorp Energy Company. Although we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit, and we intend to vigorously defend the action.
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.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 4A. Executive Officers of Forest.
The following persons were serving as executive officers of Forest as of February 16, 2012.
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(1)
Officers are appointed to serve for one-year terms at the board meeting immediately following the last annual meeting, or until their death, resignation, or removal from office, whichever first occurs.
PART II
Item 5.
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 16, 2012, our Common Stock was held by 653 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, as well as adjusted prices per share of the Common Stock that reflect the stock dividend distributed by Forest on September 30, 2011. There were no cash dividends declared on the Common Stock in 2010 or 2011. On February 16, 2012, the closing price of Forest Common Stock was $14.40.
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(1)
On September 30, 2011, Forest completed the spin-off of Lone Pine by means of a special stock dividend distributed to all shareholders of Forest Common Stock. The stock dividend consisted of .61248511 shares of Lone Pine for each outstanding share of Forest Common Stock. Based on this ratio, the value of the stock dividend to Forest shareholders is deemed by Forest to be equal to $4.18, or the average of the high and low intraday sales prices per share of Lone Pine common stock on September 30, 2011 multiplied by .61248511.
The prices shown in the "As Adjusted" column above for the first quarter of 2010 through the third quarter of 2011 have been adjusted to reflect the stock dividend paid on September 30, 2011. The ratio used for this historical price adjustment is .2901. This represents the ratio of (a) $4.18 to (b) $14.41, the average of the high and low intraday sales prices per share of Forest Common Stock on September 30, 2011.
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 concerning Forest's 8½% senior notes due 2014 and Forest's 7¼% senior notes due 2019, and (iv) Forest's bank credit facility dated as of June 30, 2011. 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 March 2, 2006, Forest distributed a special stock dividend in connection with the spin-off of its offshore Gulf of Mexico operations and, as noted above, 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, 2011.
Issuer Purchases of Equity Securities
The table below sets forth information regarding repurchases of our Common Stock during the quarter ended December 31, 2011. 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 and phantom stock units that are settled in shares. Forest does not consider this a share buyback program.
Stock Performance Graph
The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2006 (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.
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.
Item 6.
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, 2011. This data should be read in conjunction with Part II, Item 7
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 the Notes to Consolidated Financial Statements.
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, 2011, were approximately 1,904 Bcfe. At December 31, 2011, approximately 97% of our estimated proved reserves were in the United States. Having spun-off our Canadian operations on September 30, 2011, we currently conduct our operations in one reportable geographical segment - the United States. Our core operational areas are in the Texas Panhandle, the East Texas / North Louisiana area, and the Eagle Ford Shale in South Texas. See Item 1 - "Business" for a discussion of our business strategy and core operational areas of focus.
In December 2010, we announced our intention to separate our Canadian operations through an initial public offering of up to 19.9% of the common stock of our then wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which would hold our ownership interests in our Canadian operations, followed by a distribution, or spin-off, of the remaining shares of Lone Pine held by us to our shareholders. The offering occurred in June 2011, whereby we retained approximately 82% of the outstanding shares of Lone Pine's common stock. Lone Pine used the net proceeds from the offering, along with borrowings under its credit facility, to pay us approximately $29 million, as partial consideration for our contribution to Lone Pine of our interests in the Canadian operations, and to repay an intercompany note and intercompany advances and accrued interest of approximately $401 million. The spin-off of our remaining shares of Lone Pine to our shareholders was completed on September 30, 2011. As a result of the spin-off, Lone Pine’s results of operations are reported as discontinued operations in our Consolidated Statements of Operations for all periods presented.
2011 Highlights
Forest's 2011 highlights are as follows:
•
Completed an initial public offering and the subsequent spin-off of Lone Pine to Forest shareholders. Each Forest shareholder of record on September 16, 2011 received approximately .6125 shares of Lone Pine stock for every share of Forest stock held.
•
Drilled or participated in 127 gross (68 net) wells in the United States in 2011 including 68 gross (33 net) horizontal wells in the Texas Panhandle with 20 gross wells targeting two new oil zones and three additional liquids-rich gas intervals, bringing the total number of productive intervals to 11 in the Texas Panhandle.
•
Continued the initial development of our acreage in the Eagle Ford Shale oil window with the drilling of 15 wells focusing on optimizing the development of the resource. This optimization included taking core samples, acquiring 3-D seismic, the utilization of micro-seismic during horizontal well completion, and testing different sections of the Eagle Ford Shale.
•
Initiated the acquisition of undeveloped leaseholds in the Permian Basin in West Texas. As of February 21, 2012 we have acquired over 126,000 gross acres (114,500 net) in the area at an average cost of approximately $1,300 per acre. The acreage position includes 51,500 net acres prospective for the Wolfcamp shale in Crockett County, Texas and 63,000 net acres prospective for the Wolfbone intervals in Pecos and Reeves Counties, Texas.
Recent Trends and 2012 Outlook
Beginning in the second half of 2008 and continuing throughout 2011, the United States and other industrialized countries experienced a significant economic slowdown. During the same time period, North American natural gas supply increased as a result of increased domestic unconventional natural gas development and associated natural gas from oil development. In the second half of 2008, oil and natural gas prices declined dramatically. While oil and NGL prices have steadily improved since the first quarter of 2009, North American natural gas prices have remained at low levels and declined further in late-2011 as a result of increased supply and weak domestic demand in the United States. We do not plan on natural
gas prices improving significantly in 2012. As a result, as we did in 2011, we plan to direct the majority of our exploration and development capital expenditures in 2012 to more liquids-rich prospects. See Item 1 - "Business-Core Operational Areas" for a summary of our core operational areas of focus.
Results of Operations
The following table sets forth selected operating results for the years ended December 31, 2011, 2010, and 2009.
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(1)
In addition to reporting net earnings (loss) from continuing operations as defined under generally accepted accounting principles (“GAAP”), we also present Adjusted EBITDA from continuing operations, which is a non-GAAP performance measure. See "-Reconciliation of Non-GAAP Measure" at the end of this Item 7 for a reconciliation of Adjusted EBITDA from continuing operations to reported net earnings (loss) from continuing operations, which is the most directly comparable financial measure calculated and presented in accordance with GAAP.
Our net earnings (loss) from continuing operations and diluted earnings (loss) per share from continuing operations presented in the table above were primarily impacted by changes in oil, natural gas, and NGL production volumes and prices, changes in realized and unrealized derivative gains and, in 2009, a non-cash ceiling test write-down of $1.4 billion. See below for further discussion of these items. Adjusted EBITDA from continuing operations, which excludes the effects of ceiling test write-downs and other non-cash items, was also primarily impacted by changes in oil, natural gas, and NGL production volumes and prices for the periods presented, as well as changes in realized derivative gains.
Management's analysis of the individual components of the changes in our annual results follows.
Oil and Natural Gas Volumes and Revenues
Oil, natural gas, and natural gas liquids ("NGL") sales volumes, revenues, and average sales prices from continuing operations for the years ended December 31, 2011, 2010, and 2009, are set forth in the table below.
Our reported oil, natural gas, and NGL sales volumes from continuing operations decreased 11% in 2011 compared to
2010 primarily due to a decrease in natural gas production, which resulted from our decision to reduce capital expenditures for dry gas wells in response to declining natural gas prices. In 2011, we redirected capital expenditures from dry gas well development towards liquids and oil-rich prospects, including the early-stage development of our Eagle Ford oil play and the acquisition of new leaseholds in the Permian Basin prospective for oil development. Oil and natural gas revenues were essentially flat between 2010 and 2011, primarily due to an increase in oil and NGL prices that was offset by a decrease in natural gas production and prices.
Our reported oil, natural gas, and NGL sales volumes from continuing operations decreased 11% in 2010 compared to 2009. The decrease was due to oil and gas property divestitures that occurred primarily in late 2009 partially offset by production increases attributable to new wells drilled in 2010. Oil and natural gas revenues in 2010 were $708 million, an 8% increase as compared to $656 million in 2009. Oil and natural gas revenues increased due to the 22% increase in the average realized sales price per Mcfe, partially offset by the decrease in sales volumes discussed above.
The revenues and average sales prices reflected in the table above exclude the effects of commodity derivative instruments since we have elected not to designate our derivative instruments as cash flow hedges. See-"Realized and Unrealized Gains and Losses on Derivative Instruments" below for more information on gains and losses relating to our commodity derivative instruments.
Production Expense
The table below sets forth the detail of production expense from continuing operations for the periods indicated.
Lease Operating Expenses
Lease operating expenses in 2011 were $99 million, or $.81 per Mcfe, compared to $92 million, or $.67 per Mcfe, in 2010. The $.14 per Mcfe increase in 2011 compared to 2010 was primarily due to an increase in water handling costs and an increase in the number of producing oil properties that have higher average per-unit operating costs. Lease operating expenses were $92 million, or $.67 per Mcfe, in 2010 compared to $119 million, or $.77 per Mcfe, in 2009. The decrease in total and per-unit lease operating expenses was primarily due to oil and gas property divestitures that occurred during late 2009. The properties divested had higher average per-unit operating costs as compared to the properties we retained.
Production and Property Taxes
Production and property taxes, which primarily consist of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 5.8%, 6.2%, and 6.1% of oil, natural gas, and NGL revenues for the years ended December 31, 2011, 2010, and 2009, respectively. Normal fluctuations occur in the percentage between periods based upon the approval of incentive tax credits in Texas, changes in tax rates, and changes in the assessed values of oil and gas properties and equipment for purposes of ad valorem taxes.
Transportation and Processing Costs
Transportation and processing costs were $14 million, or $.11 per Mcfe, in 2011, $13 million, or $.10 per Mcfe, in 2010, and $13 million, or $.08 per Mcfe, in 2009.
General and Administrative Expense
The following table summarizes the components of general and administrative expense from continuing operations for the periods indicated.
General and administrative expense was $65 million in each of the years presented. Stock-based compensation costs and general and administrative costs capitalized under the full cost method of accounting increased in 2011 due to the recognition of $12 million ($7 million of expense, net of capitalized amounts) of costs in the third quarter of 2011 due 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. This increase in stock-based compensation costs was partially offset by a decrease in stock-based compensation costs due to a decline in our stock price in 2011. The percentage of general and administrative costs capitalized remained consistent between the three years presented, ranging between 39% and 42%.
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") increased $.43 per Mcfe to $1.80 in 2011 compared to $1.37 in 2010. The increase in DD&A is primarily due to ceiling test write-downs recorded as of December 31, 2008 and March 31, 2009 as well as the sale of oil and gas assets in the fourth quarter of 2009, which together reduced our DD&A rate to $1.25 in the first quarter of 2010. Our depletion rate has steadily increased thereafter as we have added proved oil and natural gas reserves to our depletable base at per-unit rates that have exceeded $1.25 per Mcfe.
Ceiling Test Write-Down of Oil and Gas Properties
Pursuant to the ceiling test limitation prescribed by the SEC for companies using the full cost method of accounting, Forest recorded a non-cash ceiling test write-down for its United States cost center totaling $1.4 billion in the first quarter 2009. The write-down was a result of significant declines in oil and natural gas prices in the first quarter of 2009. See-"Critical Accounting Policies, Estimates, Judgments and Assumptions-Full Cost Method of Accounting."
Interest Expense
The following table summarizes interest expense from continuing operations for the periods indicated.
Interest expense totaled $150 million in both 2011 and 2010. In December 2011, we redeemed $285 million of 8% senior notes using cash on hand and borrowings under our credit facility, with such redemption expected to result in lower total interest costs in 2012. Interest expense in 2010 totaled $150 million compared to $161 million in 2009. The $11 million decrease in interest expense was primarily due to a decrease in average debt levels in 2010 compared to 2009. In January 2010, we redeemed $150 million of 7¾% senior notes. In addition, in December 2009, we repaid all amounts outstanding under our credit facility. Interest costs capitalized relate to our investments in significant unproved acreage positions that are under development.
In order to effectively reduce the concentration of fixed-rate debt anticipated after the completion of our 2009 oil and gas property divestiture program and the related reduction in our credit facility balance, we entered into fixed-to-floating interest rate swaps in the first quarter of 2009 under which we have swapped, as of December 31, 2011, $500 million in notional amount at an 8.5% fixed rate for an equal notional amount at a weighted-average interest rate equal to the 1-month LIBOR plus approximately 5.9%. We recognized realized gains under these interest rate swaps of $11 million during each of the years ended December 31, 2011 and 2010 and $7 million during the year ended December 31, 2009. These gains are recorded as realized gains on derivatives rather than as a reduction to interest expense since we have not elected to use hedge accounting. See Note 9 to the Consolidated Financial Statements for more information on our interest rate derivatives.
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 recognized under "Costs, expenses, and other" in our Consolidated Statements of Operations for the periods indicated. See Note 8 and Note 9 to the Consolidated Financial Statements for more information on our derivative instruments.
Other, Net
The table below sets forth the components of "Other, net" from continuing operations for the periods indicated.
Accretion of Asset Retirement Obligations
Accretion of asset retirement obligations is the expense recognized to increase the carrying amount of the liability associated with our asset retirement obligations as a result of the passage of time. See Note 1 to the Consolidated Financial Statements for more information on our asset retirement obligations.
Legal Proceeding Settlement
During the second quarter of 2011, we settled litigation relating to the 2007 sale of our Alaska assets to Pacific Energy Resources, Ltd. ("PERL"), which included claims in excess of $250 million. PERL and the other plaintiffs released us from all claims and agreed to dismiss the complaint against us in exchange for a $7 million payment from us.
Gain on Debt Extinguishment
The net gain on debt extinguishment for the year ended December 31, 2010 includes the net gain related to the January 2010 redemption of our $150 million 7¾% senior notes due 2014 at 101.292% of par. A net gain was recognized due to the write-off, at the time the notes were redeemed, of unamortized deferred gains resulting from the previous termination of interest rate swaps related to these notes. This gain was partially offset by the $2 million redemption premium paid to redeem the notes. See Note 3 to the Consolidated Financial Statements for more information on our debt.
Income Tax
The table below sets forth the total income tax and effective income tax rates related to continuing operations for the periods indicated.
Our effective income tax rate generally approximates 37% to 38%. Our effective income tax rate was 48%, 37%, and 37% for the years ended December 31, 2011, 2010, and 2009, respectively. Our effective income tax rate was 48% for the year ended December 31, 2011 due to the 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. Without the $29 million dividend tax, our effective income tax rate would have been 38% in 2011. See Note 4 to the Consolidated Financial Statements for a reconciliation of income tax computed by applying the United States federal statutory income tax rates for each period presented.
Discontinued Operations
The results of operations of Lone Pine are presented as discontinued operations in our Consolidated Statements of
Operations due to the spin-off of Lone Pine on September 30, 2011, with prior periods’ results recast to conform with the discontinued operations presentation. Earnings from discontinued operations was negatively impacted by a ceiling test write-down in the Canadian cost center of $199 million during 2009. See Note 13 to the Consolidated Financial Statements for more information regarding the components of 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 NGLs directly impact our level of cash flow generated from operations. Natural gas accounted for approximately 72% of our total production in 2011 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 price for oil and NGLs. 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 16, 2012, we had hedged, via commodity swaps, approximately 67 Bcfe of our total projected 2012 production and approximately 29 Bcf of our total projected 2013 production, excluding outstanding commodity swaptions and put options. This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production in 2012. 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 16, 2012, all of our derivative instrument counterparties are lenders, or affiliates of lenders, under our credit facility, with the exception of one counterparty. See Part II, Item 7A
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, crude 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, or to protect the economics of property acquisitions, we make use of a commodity hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other derivative instruments with counterparties who, in general, are lenders, or affiliates of such lenders, 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.
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. As of December 31, 2011, we had entered into the following swaps:
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(1)
During the fourth quarter, we entered into derivative agreements for the period April 2012 - December 2012 subjecting 50 Bbtu per day of the 2012 gas swaps to a written put of $3.53 and a $4.00 to $4.50 call spread whereby we receive $5.30 except as follows: we receive (i) NYMEX HH plus $1.77 when NYMEX HH is below $3.53; (ii) $5.30 plus the value of the call spread when NYMEX HH is between $4.00 and $4.50; and (iii) $5.80 when NYMEX HH is $4.50 or above. The fair value of these derivative agreements as of December 31, 2011 was a liability of $5.8 million.
Commodity Options
In connection with several natural gas swaps entered into, we granted option instruments to the natural gas swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas swaps. The table below sets forth the outstanding options as of December 31, 2011 (as of February 16, 2012, none of the swaptions in the table have been exercised by the counterparties).
The estimated fair value of all our commodity derivative instruments based on various inputs, including published forward prices, at December 31, 2011 was a net asset of approximately $51 million.
Due to the volatility of oil, natural gas, and NGL 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, natural gas, and NGL prices used to calculate the fair values of our commodity derivative instruments at December 31, 2011 would decrease the net fair value of our commodity derivative instruments at December 31, 2011 by approximately $39 million to a net asset of $12 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 related to our commodity derivative instruments will likely differ from those estimated at December 31, 2011 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
Derivative Instruments Entered Into Subsequent to December 31, 2011
Subsequent to December 31, 2011, through February 16, 2012, we entered into the following derivative agreements:
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(1)
In connection with entering into these natural gas swaps with premium hedged prices, we granted oil puts to the counterparties, giving the counterparties the option to put 5,000 barrels per day to us at $75.00 per barrel on a monthly basis during April 2012 - December 2012.
(2)
In connection with entering into these natural gas swaps with premium hedged prices, we granted some of the counterparties with the option to enter into oil swaps with us for Calendar 2014 covering 3,000 barrels per day at a weighted average hedged price per barrel of $109.67, with such options expiring in December 2013, and granted the other counterparties with the option to enter into natural gas swaps with us for Calendar 2013 covering 20 Bbtu per day at a weighted average hedged price per MMBtu of $4.02, with such options expiring in December 2012.
Interest Rate Risk
We periodically enter into interest rate derivative agreements in an attempt to manage the mix of fixed and floating interest rates within our debt portfolio. As of December 31, 2011, we had entered into the following fixed-to-floating interest rate swaps:
The estimated fair value of all our interest rate derivative instruments based on various inputs, including published forward rates, at December 31, 2011 was an asset of approximately $21 million.
Due to the volatility of interest rates, the estimated fair values of our interest rate derivative instruments are subject to
fluctuations from period to period. For example, a hypothetical 10% increase in the forward 1-month LIBOR interest rates used to calculate the fair values of our interest rate derivative instruments at December 31, 2011 would decrease the net fair value of our interest rate derivative instruments at December 31, 2011 by approximately $1 million to an asset of $20 million. Actual gains or losses recognized related to our interest rate derivative instruments will likely differ from those estimated at December 31, 2011 and will depend exclusively on the future 1-month LIBOR interest rates.
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, 2011, beginning with the fair value of our derivative contracts on December 31, 2010. 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, natural gas, and NGL 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, 2011 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
Interest Rates on Borrowings
The following table presents principal amounts and related interest rates by year of maturity for Forest's debt obligations at December 31, 2011:
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(1)
As of December 31, 2011.
(2)
The effective interest rates on the senior notes differ from the fixed interest rates due to the amortization of related discounts or premiums on the notes.
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 Forest outside of North America have been primarily United States dollar-denominated.
Item 8.
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 and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2011. 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 and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, effective December 31, 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
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, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Denver, Colorado
February 21, 2012
FOREST OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Amounts)
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In Thousands)
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Continued)
(In Thousands)
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010, and 2009
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Description of the Business
Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids (“NGLs”) primarily in 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 and has exploratory and development interests in two other countries. In December 2010, Forest announced its intention to separate its Canadian operations through an initial public offering of up to 19.9% of the common stock of its subsidiary, Lone Pine Resources Inc. (“Lone Pine”), followed by a distribution, or spin-off, of the remaining shares of Lone Pine held by Forest to its shareholders. On June 1, 2011, Lone Pine completed an initial public offering of 15 million shares of common stock. On September 30, 2011, Forest completed the spin-off of the 70 million shares of Lone Pine held by Forest in the form of a pro rata common stock dividend to all Forest shareholders. 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. The results of operations of Lone Pine are reported as discontinued operations due to the spin-off, with prior periods being recast for comparative purposes. All intercompany balances and transactions have been eliminated. Certain amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation.
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 and gas 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, determining impairments of investments in unproved properties, valuing deferred tax assets and goodwill, 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
In January 2010, the Financial Accounting Standards Board (‘‘FASB’’) issued oil and natural gas reserves estimation and disclosure authoritative accounting guidance effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserves estimation and disclosure requirements with the requirements in the Securities and Exchange Commission’s (‘‘SEC’’) final rule, ‘‘Modernization of Oil and Gas Reporting’’, which was also effective for annual reports for fiscal years ending on or after December 31, 2009. These rules included, among other things, changes to pricing used to estimate oil and natural gas reserves, broadened the types of technologies that a company may use to establish oil and natural gas reserves estimates, and broadened the definition of oil and natural gas producing activities. Accordingly, the Company adopted both the FASB’s authoritative accounting guidance and the SEC’s rule as of December 31, 2009.
The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which the Company has operations. During the periods presented, the Company's primary oil and gas operations were conducted in the United States and Canada. Upon the spin-off of Lone Pine on September 30, 2011, the Company no longer has any 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. For the years ended December 31, 2011, 2010, and 2009, Forest's continuing operations capitalized $46.4 million, $42.6 million, and $41.5 million of general and administrative costs (including stock-based compensation), respectively. Interest costs related to significant unproved properties that are under development are also capitalized to oil and gas properties. During 2011, 2010, and 2009, Forest's continuing operations capitalized $10.3 million, $11.2 million, and $12.2 million, respectively, of interest costs attributed to unproved properties.
Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed 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, 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 assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.
The Company performs a ceiling test each quarter on a country-by-country basis. 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 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 (as discussed below), excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. The December 31, 2011 ceiling test did not result in a write-down. The March 31, 2009 ceiling test resulted in a non-cash write-down of oil and gas property costs of $1.4 billion in the United States cost center.
Gain or loss is not recognized on the sale of oil and gas properties unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and gas reserves attributable to a cost center.
Depletion of proved oil and 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 has historically updated its quarterly depletion calculations with its quarter-end reserves estimates. Based on this accounting policy, the December 31, 2011 reserves estimates were used for the Company's fourth quarter 2011 depletion calculation.
Gas gathering assets are depreciated on the units-of-production method whereby the capitalized costs are amortized over the total estimated throughput of the system. 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 gas properties.
The following table summarizes the activity for the Company's asset retirement obligations of its continuing operations for the periods indicated:
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 a receivable is accrued. At December 31, 2011 and 2010, the Company had gas imbalance payables of $7.8 million and $7.7 million, respectively, and gas imbalance receivables of $6.9 million and $7.0 million, respectively.
In 2011, sales to one purchaser were approximately 22%, or $151.9 million, of the Company's total revenues from continuing operations. In 2010, sales to two purchasers were approximately 20%, or $145.1 million, and 10%, or $73.2 million, respectively, of the Company's total revenues from continuing operations. In 2009, sales to two purchasers were approximately 17%, or $108.6 million, and 10%, or $66.9 million, respectively, 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.
Accounts Receivable
The components of accounts receivable related to continuing operations 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 per share is required to be used since Forest has participating securities. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Holders of restricted stock issued under Forest's stock incentive plans have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock. Holders of phantom stock units issued to directors under Forest's stock incentive plans also have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock, while phantom stock units issued to employees do not participate in dividends. Stock options issued under Forest's stock incentive plans do not participate in dividends. Performance units issued under Forest's stock incentive plans do not participate in dividends in their current form. Holders of performance units participate in dividends paid during the performance units' vesting period only after the performance units vest with common shares being earned by the holders of the performance units. Performance units may vest with no common shares being earned, 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.
Under the treasury stock method, diluted earnings (loss) per share is computed by dividing (a) net earnings (loss), adjusted for the effects of certain contracts that provide the issuer or holder with a choice between settlement methods, by (b) the weighted average number of common shares outstanding, adjusted for the dilutive effect, if any, of potential common shares (e.g. stock options, unvested restricted stock grants, unvested phantom stock units that may be settled in shares, and unvested performance units). No potential common shares are included in the computation of any diluted per share amount when a net loss exists. Unvested restricted stock grants were not included in the calculations of diluted earnings per share for the years ended December 31, 2011 and 2010 as their inclusion would have an antidilutive effect. Stock options, unvested restricted stock grants, and unvested phantom stock units that may be settled in shares were not included in the calculation of diluted loss per share for the year ended December 31, 2009 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.
The following reconciles basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the periods presented.
Stock-Based Compensation
Compensation cost is measured at the grant date based on the fair value of the awards (stock options, restricted stock, performance units, employee stock purchase plan rights) or is measured at the reporting date based on the current stock price (phantom stock units), and is recognized on a straight-line basis over the requisite service period (usually the vesting period).
Derivative Instruments
The Company records all derivative instruments as either assets or liabilities at fair value, other than the derivative instruments that meet the normal purchases and sales exception. The Company has not elected to designate its derivative instruments as hedges and, therefore, records all changes in fair value of its derivative instruments through earnings, with such changes reported in a single line item on the statements of operations together with 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, 2011 and 2010 totaled $25.0 million and $23.9 million, respectively, and are being amortized over the life of the respective debt instruments.
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 $10.1 million and $22.6 million of materials and supplies as of December 31, 2011 and 2010, 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 make an annual impairment assessment 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 events or circumstances change between annual tests indicating a possible impairment. The impairment assessment requires the Company to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. Although the Company bases its fair value estimate on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and uncertain. Downward revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or depressed oil and natural gas prices could lead to an impairment of goodwill in future periods. The Company had no goodwill impairments for the years ended December 31, 2011, 2010, and 2009.
Comprehensive Earnings (Loss)
Comprehensive earnings (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 changes in the unfunded postretirement benefits.
The components of accumulated other comprehensive income (loss) for the years ended December 31, 2011, 2010, and 2009 are as follows:
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(1)
Net of income tax expense (benefit) of $(3.7) million, $(.5) million, and $1.2 million for 2011, 2010, and 2009, respectively.
Impact of Recently Issued Accounting Pronouncements
In May 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income, Presentation of Comprehensive Income (“ASU 2011-05”), which provides amendments that will result in more converged guidance on how comprehensive income is presented under U.S. generally accepted accounting principles (“U.S. GAAP”) and International Financial Reporting Standards (“IFRS”). ASU 2011-05 requires an entity to present items of net income, items of other comprehensive income, and total comprehensive income either in a single continuous statement or in two separate consecutive statements and eliminates the option to report other comprehensive income and its components in the statement of shareholders’ equity. ASU 2011-05 also requires entities to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income. In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which indefinitely defers the requirements in ASU 2011-05 to present on the face of the financial statements the effects of reclassifications out of accumulated other
comprehensive income on the components of net income and other comprehensive income. Both ASU 2011-05 and ASU 2011-12 are effective for interim and annual periods beginning after December 15, 2011, and should be applied retrospectively. The adoption of this authoritative guidance will not have an impact on Forest's financial position or results of operations, but will require Forest to present the statements of comprehensive income separately from the statements of shareholders' equity, as these statements are currently presented on a combined basis.
In June 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which amends the current U.S. GAAP fair value measurement and disclosure guidance, to converge U.S. GAAP and IFRS requirements for measuring amounts at fair value as well as disclosures about these measurements. Many of the amendments clarify existing concepts and are not expected to result in significant changes to how companies apply the fair value principles. This authoritative guidance is effective for interim and annual periods beginning after December 15, 2011. Forest is currently evaluating the impact that the adoption of this authoritative guidance will have on its fair value measurements and disclosures.
In September 2011, the FASB issued Accounting Standards Update No. 2011-08, Intangibles-Goodwill and Other (Topic 350), Testing Goodwill for Impairment (“ASU 2011-08”), which permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount to determine whether it is necessary to perform the two-step goodwill impairment test. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. However, if an entity concludes otherwise, it is required to perform the first step of the two-step impairment test, which may then lead an entity to performing the second step as well. Entities have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to the first step of the two-step impairment test. This authoritative guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of this authoritative accounting guidance may change the methodology Forest uses to test its goodwill for impairment depending on the events or circumstances at the time the test is performed.
In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”), which requires that an entity disclose both gross and net information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement, including derivative instruments. ASU 2011-11 was issued in order to facilitate comparison between U.S. GAAP and IFRS financial statements by requiring enhanced disclosures, but does not change existing U.S. GAAP that permits balance sheet offsetting. This authoritative guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The adoption of this authoritative guidance will not have an impact on Forest's financial position or results of operations, but will require Forest to make enhanced disclosures regarding its derivative instruments.
(2) PROPERTY AND EQUIPMENT:
Net property and equipment of continuing operations consists of the following as of the dates indicated:
__________________________________________
(1)
At December 31, 2011 and 2010, $98.7 million and $91.6 million, respectively, of the Company's total net property and equipment of continuing operations was located in foreign countries. The remaining total net property and equipment was located in the United States.
The following table sets forth a summary of Forest's investment in unproved properties as of December 31, 2011, by the year in which such costs were incurred:
The majority of the U.S. unproved oil and gas property costs, or those not being depleted, relate to oil and 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 in the U.S. as of December 31, 2011 will be reclassified to proved properties within ten years. Forest's exploration project in South Africa accounts for all of the international costs not being amortized as of December 31, 2011. The Company continues to pursue commercial development of the Ibhubesi field discovery in South Africa including continued efforts toward securing gas sales contracts.
Divestitures
During the years ended December 31, 2011 and 2010, Forest sold various U.S. oil and natural gas properties for total proceeds of $121.0 million and $75.9 million, respectively. During 2010, Forest also entered into sale-leaseback transactions involving drilling rigs, receiving $63.1 million in total proceeds. During 2009, Forest sold all of its oil and natural gas properties located in the Permian Basin in West Texas and New Mexico for approximately $908.3 million in cash and also sold other
U.S. oil and natural gas properties for total proceeds of $25.0 million.
Acquisitions - Subsequent Event
In February 2012, the Company paid $66.0 million in cash and issued 2.7 million shares of common stock, valued at approximately $36 million, pursuant to a lease purchase agreement whereby Forest acquired leases on unproved oil and natural gas properties in the Wolfbone oil play in the Permian Basin in Texas.
(3) DEBT:
The components of debt are as follows:
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(1)
Represents the unamortized portion of deferred gains realized upon the termination of interest rate swaps in 2002 that were accounted for as fair value hedges. The gains were amortized as a reduction of interest expense over the terms of the notes.
(2)
Redeemed in December 2011.
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., consisting of a $1.5 billion credit facility maturing in June 2016. Subject to the agreement of Forest and the applicable lenders, the size of the Credit Facility may be increased by $300.0 million, to a total of $1.8 billion.
Forest’s availability under the Credit Facility is governed by a borrowing base. As of December 31, 2011, the borrowing base under the Credit Facility was $1.25 billion. 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 gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and 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. The borrowing base was reaffirmed at $1.25 billion in October 2011 and the next scheduled redetermination of the borrowing base will occur on or about May 1, 2012.
The borrowing base is also subject to change in the event (i) Forest or its Restricted Subsidiaries 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 then-existing senior notes, or (ii) Forest sells oil and natural gas properties included in the borrowing base having a fair market value in excess of 10% of the borrowing base then in effect. A lowering of the borrowing base could require Forest to repay indebtedness in excess of the borrowing base in order to cover the deficiency.
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 Credit Facility provides that Forest will not permit its ratio of total
debt outstanding to consolidated EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period to be greater than 4.50 to 1.00 at any time.
Under certain conditions, amounts outstanding under the Credit Facility may be accelerated. 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. Subject to notice and cure periods, certain events of default under the Credit Facility will result in acceleration of the indebtedness under the Credit Facility at the option of the lenders. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the Credit Facility (including the financial covenant), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility.
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 gas properties and related assets of Forest and its U.S. subsidiaries. Forest is required to pledge, and has pledged, the stock of certain subsidiaries to secure the Credit Facility. If Forest’s corporate credit rating by Moody’s and S&P 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.
Of the $1.5 billion total nominal amount under the Credit Facility, JPMorgan and eleven other banks hold approximately 68% of the total commitments, with each of these twelve lenders holding an equal share. 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, 2011, there were outstanding borrowings of $105.0 million under the Credit Facility at a weighted average interest rate of 2.1% 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 $1.1 billion.
Prior to entering into the Credit Facility, the previous combined credit facility, the Second Amended and Restated Credit Agreement dated as of June 6, 2007, consisting of U.S. and Canadian facilities (the “Combined Credit Facility”) was amended on May 25, 2011, to, among other things, remove any collateral owned by Lone Pine or any of its subsidiaries from the collateral securing the U.S. portion of the Combined Credit Facility, terminate the previous Canadian portion of the Combined Credit Facility, terminate various guaranties securing the Canadian portion of the Combined Credit Facility, release collateral securing the Canadian portion of the Combined Credit Facility, and terminate certain liens and mortgages securing the Canadian portion of the Combined Credit Facility.
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 are 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. Due to the amortization of the discount, the effective interest rate on the 8½% Notes is 9.47%.
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%.
Forest may redeem the 7¼% Notes at any time beginning on or after June 15, 2012 at the prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued but unpaid interest:
Forest may also redeem the 7¼% Notes, in whole or in part, at a price equal to the principal amount plus a make-whole premium, at any time prior to June 15, 2012, using a discount rate of the Treasury rate plus 0.50%, plus accrued but unpaid interest.
8% Senior Notes Due 2011
In December 2001, Forest issued $160.0 million in principal amount of 8% senior notes due 2011 (the "8% Notes") at par for proceeds of $157.5 million (net of related offering costs). In July 2004, Forest issued an additional $125.0 million in principal amount of 8% Notes at 107.75% of par for proceeds of $133.3 million (net of related offering costs). In December 2011, Forest redeemed the 8% Notes.
7¾% Senior Notes Due 2014
In December 2009, Forest notified the trustee and note holders of the $150.0 million of 7¾% senior notes due 2014 (the "7¾% Notes") that it was calling the 7¾% Notes. This notice was irrevocable after it was given.
The 7¾% Notes were redeemed in January 2010 at 101.292% of par and a net gain of $4.6 million was recognized in January 2010 upon redemption. The net gain was recognized due to the write-off of unamortized deferred gains that resulted from the previous termination of interest rate swaps related to the 7¾% Notes.
Principal Maturities
Principal maturities of the Company's debt at December 31, 2011 are as follows:
(4) INCOME TAXES:
Income Tax Provision
The table below sets forth the provision for income taxes from continuing operations for the periods presented.
Income (loss) from continuing operations before income taxes consists of the following 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 income from continuing operations is as follows:
Net Deferred Tax Assets and Liabilities
The components of the net deferred tax assets and liabilities of Forest's continuing operations at December 31, 2011 and 2010 are as follows:
The net deferred tax assets and liabilities are reflected in the Consolidated Balance Sheets as follows:
Tax Attributes
Net Operating Losses
U.S. federal net operating loss carryforwards ("NOLs") at December 31, 2011 were approximately $169.7 million, with $8.2 million scheduled to expire in 2019, $1.4 million scheduled to expire in 2020, and the remaining scheduled to expire after 2030.
The statute of limitations is closed for the Company's U.S. federal income tax returns for years ending on or before December 31, 2007. Pre-acquisition returns of acquired businesses are also closed for tax years ending on or before December 31, 2007. 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, 1999.
Alternative Minimum Tax Credits
The Alternative Minimum Tax credit carryforward available to reduce future U.S. federal regular taxes equaled an aggregate amount of $54.8 million at December 31, 2011, 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.
(5) SHAREHOLDERS' EQUITY:
Common Stock
At December 31, 2011, the Company had 200.0 million shares of common stock, par value $.10 per share, authorized and 114.5 million shares issued and outstanding.
In May 2009, the Company issued 14.4 million shares of common stock at a price of $18.25 per share. Net proceeds from this offering were $256.2 million after deducting underwriting discounts and commissions and offering expenses.
In February 2012, the Company issued 2.7 million shares of common stock, valued at approximately $36 million, as partial consideration pursuant to a lease purchase agreement whereby Forest acquired leases on unproved oil and natural gas properties in the Wolfbone oil play 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 Articles of Incorporation. Of those, 7.4 million shares are designated as Senior Preferred Stock and 2.7 million shares are designated as Junior Preferred stock. No preferred stock is issued or outstanding.
Lone Pine
In December 2010, Forest announced its intention to separate its Canadian operations through an initial public offering of up to 19.9% of the common stock of its wholly-owned subsidiary, Lone Pine, which would hold Forest’s ownership interests in its Canadian operations, followed by a distribution, or spin-off, of Forest's remaining shares of Lone Pine to Forest's shareholders. 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 “Income tax” on the Consolidated Statement of Operations. On June 1, 2011, Lone Pine completed an initial public offering of 15 million shares of its common stock at a price of $13.00 per share ($12.22 per share net of underwriting discounts and commissions). Upon completion of the offering, Forest retained controlling interest in Lone Pine, owning approximately 82% of the outstanding shares of Lone Pine’s common stock. The net proceeds from the offering received by Lone Pine, after deducting underwriting discounts and commissions and offering expenses, were approximately $178.0 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 Lone Pine’s credit facility to repay Lone Pine’s outstanding indebtedness owed to Forest, consisting of a note payable, intercompany advances, and accrued interest, of $400.5 million. Forest completed the spin-off of its remaining shares of Lone Pine on September 30, 2011, in the form of a pro rata common stock dividend to all Forest shareholders of record as of the close of business on September 16, 2011 (the “Record Date”). Forest shareholders received .61248511 of a share of Lone Pine common stock for every share of Forest common stock held as of the close of business on the Record Date. 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.
Rights Agreement
In October 1993, the Board of Directors of Forest adopted a shareholders' rights plan and entered into a Rights Agreement (the "1993 Agreement"), which was amended and supplemented in October 2003 by the First Amended and Restated Rights Agreement (taken together with the 1993 Agreement, the "Rights Agreement"). Under the Rights Agreement, one Preferred Share Purchase Right (the "Rights") is issued for each outstanding share of the Company's common stock. The Rights expire on October 29, 2013, unless earlier exchanged or redeemed. The Rights entitle the holder thereof to purchase 1/100th of a preferred share at an initial purchase price of $120 and are exercisable only if a person or group acquires 20% or more of the Company's common stock or announces a tender offer that would result in ownership by a person or group of 20% or more of the common stock.
(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 8.7 million shares. As of December 31, 2011, the Company had 4.1 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, 2011.
Compensation Costs
The table below sets forth stock-based compensation of continuing operations recorded during the years ended December 31, 2011, 2010, and 2009, and the remaining unamortized amounts and weighted average amortization period as of December 31, 2011.
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(1)
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 for by the Stock-based Compensation Plans, which were designed to equalize an award’s value before and after an equity restructuring. Because the actual option modifications were calculated based on Forest’s average stock price over a period of time before and after the spin-off of Lone Pine rather than the stock price immediately before and after the spin-off, $1.1 million in incremental compensation cost resulted, $.4 million of which was capitalized. This cost was recognized in its entirety on September 30, 2011 because all options outstanding were vested as of that date.
(2)
In conjunction with the spin-off, the forfeiture restrictions on a portion of each outstanding restricted stock award lapsed because the holders of the restricted stock awards received unrestricted Lone Pine common shares in the spin-off. This resulted in an acceleration of the recognition of $10.9 million of compensation costs associated with the restricted stock awards, $4.9 million of which was capitalized.
(3)
The Company also maintains an employee stock purchase plan (which is not included in the table) under which $.5 million, $.5 million, and $.6 million of compensation costs were recognized for the years ended December 31, 2011, 2010, and 2009, respectively.
(4)
In addition to the compensation costs set forth in the table above, in June 2011 the Company granted a cash-based long-term incentive award under which $.1 million in compensation costs were recognized for the year ended December 31, 2011, and under which $.5 million remains as unamortized stock-based compensation costs at December 31, 2011. The award is comprised of time-based and performance-based components. Under the time-based component, a cash payment will be made after three years dependent on the change in value of Forest’s common stock during the three-year period, and under the performance-based component, a cash payment will be made after three years dependent on the total shareholder return on Forest’s common stock in comparison to that of a peer group during the three-year period. The cash-based long-term incentive award has been accounted for as a liability within the Consolidated Financial Statements.
(5)
Based on the closing price of the Company's common stock on December 31, 2011.
Stock Options
The following table summarizes stock option activity in the Stock-based Compensation Plans for the years ended December 31, 2011, 2010, and 2009.
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(1)
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 for by the Stock-based Compensation Plans. In conjunction with the spin-off, Lone Pine employees were deemed to have been involuntarily terminated under the terms of their option agreements and, therefore, had three months from September 30, 2011 to exercise their vested options before they were canceled.
(2)
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.
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, 2011:
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, 2011, 2010, and 2009.
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(1)
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 for by 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 for by 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 agreements, and, therefore, all phantom stock units held by Lone Pine employees vested on September 30, 2011 and were settled in cash by Lone Pine. The single Lone Pine employee who held a performance unit award was deemed to have been involuntarily terminated under the terms of his performance unit agreement at the time of the spin-off and, therefore, his performance units vested on September 30, 2011, but with no shares deliverable under his agreement. No Forest restricted stock awards were held by Lone Pine employees at the time of the spin-off.
(3)
Of the unvested units of phantom stock at December 31, 2011, 6,080 units can be settled in cash, shares of common stock, or a combination of both at the discretion of the Company, while the remaining 1,232,737 units can only be settled in cash. The phantom stock units have been accounted for as a liability within the Consolidated Financial Statements. Of the 398,857 phantom stock units that vested during 2011, 5,500 units were settled in shares of common stock and 393,357 units were settled in cash. Of the 65,140 phantom stock units that vested during 2010, 63,750 units were settled in shares of common stock and 1,390 units were settled in cash. Of the 12,109 phantom stock units that vested in 2009, 7,429 were settled in shares of common stock and 4,680 units were settled in cash.
The grant date fair value of the restricted stock was determined by averaging the high and low stock price of a share of common stock as published by the New York Stock Exchange on the date of grant. The restricted stock generally vests on the third anniversary of the date of the award, but may vest earlier upon a qualifying disability, death, retirement, certain involuntary terminations, or a change in control of the Company in accordance with the term of the underlying agreement.
The grant date fair value of the phantom stock units was determined by averaging the high and low stock price of a share of common stock as published by the New York Stock Exchange on the date of grant. Phantom stock units outstanding prior to the fourth quarter of 2011 generally vest on the third anniversary of the date of the award. In the fourth quarter of 2011, the Company granted 941,300 phantom stock units that vest in one-third increments on each of the first three anniversaries of the date of grant. Like restricted stock, phantom stock units may vest earlier due to certain circumstances, as discussed above.
Forest granted performance units to its officers on May 21, 2010 and June 10, 2011. Under the terms of the award agreements, each performance unit represents a contractual right to receive one share of Forest’s common stock; provided that the actual number of shares 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 first of which ends on March 31, 2013 and the second of which ends on March 31, 2014. 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).
Employee Stock Purchase Plan
The Company has a 1999 Employee Stock Purchase Plan (the "ESPP"), under which it is authorized to issue up to .8 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, 2011, the Company had .3 million shares available for issuance under the ESPP.
The fair value of each stock purchase right granted under the ESPP during 2011, 2010, and 2009 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:
(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 "Supplemental Executive Retirement Plan") 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 Supplemental Executive Retirement Plan 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. In conjunction with The Houston Exploration Company acquisition in June 2007, Forest assumed a non-qualified unfunded supplementary retirement plan (the "Houston Exploration SERP," and together with the "Supplemental Executive Retirement Plan," the "SERP"). The Houston Exploration SERP was curtailed and all benefit accruals were suspended effective January 1, 2008. 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, 2011, 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 2012 through 2016 and in the aggregate for the years 2017 through 2021 in the following amounts:
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(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 2012 totaling $.1 million to the Plans and $.6 million for the Postretirement Benefits Plan, net of retiree contributions and expected Medicare reimbursements, as applicable.
Benefit Obligations
The following table sets forth the estimated benefit obligations associated with the Company's Pension Plans and Postretirement Benefits Plan.
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. During 2011, the amount of contributions in the case of the Postretirement Benefit Plan, equals the amount of benefits paid.
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(1)
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 December 31, 2011, the sector weighting of this fund was comprised of the following: information technology (22%), financials (15%), energy (15%), health care (13%), consumer staples (11%), and other (24%). 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.
(2)
These two 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, 2011, the sector weighting of this fund, which seeks diversification across regions, countries, and market sectors, was comprised of the following: financials (20%), health care (17%), consumer discretionary (14%), information technology (13%), telecommunications services (11%), and other (25%). 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, 2011, 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 (29%), consumer discretionary (17%), consumer staples (16%), information technology (14%), and other (24%). 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.
(3)
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, 2011, the sector weighting of this fund was comprised of the following: investment grade corporate bonds (44%), mortgage (15%), net cash equivalents (11%), and other (30%). 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.
(4)
This investment fund consists of a diversified portfolio of bonds. The 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, 2011, the sector weighting of this fund was comprised of the following: mortgage (48%), government-related (31%), non-U.S. dollar developed market (18%), and other (3%). 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)
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.
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).
Investments of the Plans
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 to avoid a loss of 20% during any single year and to express 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:
Funded Status
The following table sets forth the funded status of the Company's Pension Plans and Postretirement Benefits Plan.
The following table sets forth the projected and accumulated benefit obligations for the Pension Plans compared to the fair value of the plan assets for the periods indicated.
Annual Periodic Expense and Actuarial Assumptions
The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions.
The discount rates used to determine benefit obligations were determined by adjusting the Moody's Aa Corporate bond yield 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 Moody's Aa index. 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, 2012, will include expense of $.9 million resulting from the amortization of its related accumulated actuarial loss included in accumulated other comprehensive
income at December 31, 2011.
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:
Other Employee Benefit Plans
Forest sponsors various defined contribution plans in the United States under which the Company contributed matching contributions equal to $3.7 million in 2011, $3.3 million in 2010, and $3.5 million in 2009.
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 2012 to maintain these life insurance policies is $1.0 million. Forest recognized accretion expense related to the split dollar life insurance obligations of $1.0 million, $1.0 million, and $1.4 million for the years ended December 31, 2011, 2010, and 2009, respectively. The discount rates used to determine the accretion expense were 4.08%, 4.01%, and 5.64% for the years ended December 31, 2011, 2010, and 2009, respectively. The split dollar life insurance obligation recognized in the balance sheet was $7.3 million and $7.3 million as of December 31, 2011 and 2010, respectively. The discount rates used to determine the obligations were 3.19% and 4.08% as of December 31, 2011 and 2010, respectively. The cash surrender value of the split dollar life insurance policies recognized in the balance sheets was $3.6 million and $3.3 million as of December 31, 2011 and 2010, respectively.
(8) FAIR VALUE MEASUREMENTS:
The Company's assets and liabilities measured at fair value on a recurring basis at December 31, 2011 and 2010 are set forth by level within the fair value hierarchy in the table below.
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(1)
The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly
observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions. The Company uses the income approach to value its derivative instruments under the Level 2 hierarchy.
(2)
The Company's derivative assets and liabilities include commodity and interest rate derivatives (see Note 9 for more information on these instruments). The Company 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, the Company's derivative instruments are included within the Level 2 fair value hierarchy.
The following table presents a reconciliation of the beginning and ending balances of the Company's assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2009. The Company did not have assets or liabilities with any fair value measured at fair value on a recurring basis using significant unobservable inputs (Level 3) at any time during 2011 or 2010.
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(1)
These debt securities consisted of a zero coupon senior subordinated note due from Pacific Energy Resources, Ltd. ("PERL") in 2014 at a principal amount at stated maturity of $60.8 million (the "PERL Note") that was received as a portion of the total consideration for the sale of the Company's Alaska assets in 2007. In March 2009, PERL filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code and the court-approved Plan of Liquidation became effective in December 2010. During 2011, the Company affirmatively released any claim on the PERL Note. Prior to that, the Company used its own assumptions as to what market participants would assume regarding future cash flows and risk-adjusted discount rates in valuing the PERL Note, which had been valued at zero since March 31, 2009.
(2)
These equity securities consisted of shares of PERL common stock, which the Company also received as a portion of the total consideration for the sale of the Company's Alaska assets in 2007. The fair value measurement of the PERL common stock was transferred from Level 1 to Level 3 in the first quarter of 2009 when PERL's common stock was suspended from trading for failure to meet the continued stock exchange listing requirements. Prior to PERL's liquidation, under which common shareholders received no value for their PERL common stock, the Company used its own assumptions as to what market participants would assume regarding future cash flows and risk-adjusted discount rates in valuing the PERL common stock, which had been valued at zero since March 31, 2009.
(3)
The Company's policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
The table below sets forth losses (realized and unrealized) included in earnings related to the Company's assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the period presented. These losses are reported in the Consolidated Statement of Operations in the "Other, net" line item. The Company did not record any gains or losses (realized and unrealized) related to assets or liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during 2011 or 2010.
The fair values and carrying amounts of the Company's financial instruments are summarized below as of the dates indicated.
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(1)
The Company used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amount of cash and cash equivalents approximated fair value due to the short original maturities (three months or less) and high liquidity of the cash equivalents. The carrying amount of the credit facility approximated fair value since borrowings bear interest at variable market rates. 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.
(9) DERIVATIVE INSTRUMENTS:
Commodity Derivatives
Forest periodically enters into commodity derivative instruments such as swap and collar agreements 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 Consolidated Statement of Operations.
The table below sets forth Forest's outstanding commodity swaps as of December 31, 2011.
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(1)
During the fourth quarter of 2011, Forest entered into derivative agreements for the period April 2012 - December 2012 subjecting 50 Bbtu per day of the 2012 gas swaps to a written put of $3.53 and a $4.00 to $4.50 call spread whereby Forest receives $5.30 except as follows: Forest receives (i) NYMEX HH plus $1.77 when NYMEX HH is below $3.53; (ii) $5.30 plus the value of the call spread when NYMEX HH is between $4.00 and $4.50; and (iii) $5.80 when NYMEX HH is $4.50 or above.
In connection with several natural gas and oil swaps entered into, Forest granted oil swaptions to the swap counterparties in exchange for Forest receiving premium hedged prices on the natural gas and oil swaps. These swaptions grant the swap counterparties the option to enter into future swaps with Forest. The table below sets forth the outstanding swaptions as of December 31, 2011 (as of February 16, 2012, none of the swaptions in the table have been exercised by the counterparties).
Derivative Instruments Entered Into Subsequent to December 31, 2011
Subsequent to December 31, 2011, through February 16, 2012, Forest entered into the following derivative agreements:
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(1)
In connection with entering into these natural gas swaps with premium hedged prices, Forest granted oil puts to the counterparties, giving the counterparties the option to put 5,000 barrels per day to Forest at $75.00 per barrel on a monthly basis during April 2012 - December 2012.
(2)
In connection with entering into these natural gas swaps with premium hedged prices, Forest granted some of the counterparties with the option to enter into oil swaps with Forest for Calendar 2014 covering 3,000 barrels per day at a weighted average hedged price per barrel of $109.67, with such options expiring in December 2013, and granted the other counterparties with the option to enter into natural gas swaps with Forest for Calendar 2013 covering 20 Bbtu per day at a weighted average hedged price per MMBtu of $4.02, with such options expiring in December 2012.
Interest Rate Derivatives
Forest periodically enters into interest rate derivative instruments in an attempt to manage the mix of fixed and floating interest rates within its debt portfolio. The Company has elected not to designate its derivatives as hedging instruments. As such, the Company recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the Consolidated Statement of Operations. The table below sets forth Forest's outstanding fixed-to-floating interest rate swaps as of December 31, 2011.
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 Note 8 for more information on the determination of 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. These derivative instruments are not designated as hedging instruments for accounting purposes.
Due to the volatility of oil and natural gas prices, the estimated fair values of Forest's commodity derivative instruments are subject to large fluctuations from period to period. Forest has experienced the effects of these commodity price fluctuations in both the current period and prior periods and expects that volatility in commodity prices will continue.
Credit Risk
Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. ("ISDA") Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes, with each of its derivative counterparties a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties' requirements and the specific types of derivatives to be traded. As of December 31, 2011, all of the 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 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, 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 derivative counterparties are all 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 $77.5 million at December 31, 2011. 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, 2011, Forest owed a net derivative liability to three counterparties, the fair value of which was $6.4 million. In the absence of netting provisions, at December 31, 2011, Forest would be exposed to a risk of loss of $100.0 million under its derivative agreements and Forest's derivative counterparties would be exposed to a risk of loss of $28.9 million.
On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted which, as part of a broader financial regulatory reform, includes derivatives reform that may impact Forest’s business. Congress delegated many of the details of the Dodd-Frank Act to federal regulatory agencies, which are in the process of writing and implementing new rules. Forest is monitoring the impact, if any, that the Dodd-Frank Act and related rules will have on its existing derivative transactions under its outstanding ISDA Master Agreements and Schedules, as well as its ability to enter into such transactions and agreements in the future.
(10) COMMITMENTS AND CONTINGENCIES:
The table below shows the Company's future rental payments under non-cancelable operating leases and unconditional purchase obligations as of December 31, 2011.
____________________________________________
(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.
(2)
Includes unconditional purchase obligations for throughput. Payments made under these unconditional purchase obligations were $.5 million, in 2011, $.4 million in 2010, and $.2 million in 2009.
Net rental payments under non-cancelable operating leases applicable to exploration and development activities and capitalized to oil and gas properties approximated $21.0 million in 2011, $14.0 million in 2010, and $10.1 million in 2009. Net rental payments under operating leases, including compressor rentals, charged to expense approximated $16.5 million in 2011, $18.4 million in 2010, and $23.6 million in 2009. The Company has no leases that are accounted for as capital leases.
In August 2007, Forest sold all of its Alaska assets to Pacific Energy Resources Ltd. and its related entities ("PERL"). On March 9, 2009, PERL filed for bankruptcy. As part of the plan of liquidation of its bankruptcy, PERL "abandoned" its interests in many of the Alaska assets sold to it by Forest, including the Trading Bay Unit and Trading Bay Field ("Trading Bay"). At the
time of the abandonment of PERL's interests in Trading Bay, Union Oil Company of California ("Unocal") was the operator of those assets. On December 2, 2010, Unocal filed a lawsuit styled Union Oil Company of California v. Forest Oil Corporation in Anchorage District Court, Alaska. Forest has removed the case to federal district court in Anchorage, Alaska. In the lawsuit, the plaintiff complains about PERL's abandonment of Trading Bay and states that PERL has failed to pay approximately $48.0 million in joint interest billings owed on those properties to date from the time PERL owned them. The plaintiff further claims that Forest is liable for PERL's share of all joint interest billings owed on Trading Bay, in arrears and in the future, because (1) Forest was the predecessor party to the contracts governing the operations at Trading Bay, (2) Unocal did not agree that, in conjunction with Forest's sale of its Alaska assets, Forest would be released of its obligations under the Trading Bay contracts, and (3) PERL has defaulted on the joint interest billings owed on Trading Bay since October 2008. As of December 31, 2011, Unocal sold its interest in the Trading Bay assets, including its claims against Forest, to Hilcorp Energy Company. Although we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit, and we intend to vigorously defend the action.
Forest, in the ordinary course of business, is a party to various other 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.
(12) SELECTED QUARTERLY FINANCIAL DATA (unaudited):
____________________________________________
(1)
Amounts shown for the first through third quarters of 2010 and first and second quarters of 2011 are those amounts that were previously reported in Forest's Quarterly Reports on Form 10-Q prior to the September 30, 2011 spin-off of Lone Pine, whose results are now reported as discontinued operations.
(2)
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.
(3)
Earnings (loss) before income taxes, net earnings (loss), and net earnings (loss) attributable to Forest Oil have been subject to large fluctuations due to Forest's election not to use cash flow hedge accounting for derivative instruments as discussed in Note 9.
(4)
Upon completion of Lone Pine's initial public offering on June 1, 2011, Forest maintained a controlling interest in Lone Pine until it was spun-off on September 30, 2011. As such, during the second and third quarters of 2011, Forest had net earnings attributable to the noncontrolling interest.
(13) DISCONTINUED OPERATIONS
Since Lone Pine was a component of Forest with operations and cash flows clearly distinguishable both operationally and for financial reporting purposes from those of Forest, and because Lone Pine’s operations and cash flows have been eliminated from the ongoing operations of Forest and Forest will not have any significant continuing involvement in the operations of Lone Pine, Forest has presented Lone Pine’s results of operations as discontinued operations in the Consolidated Statements of Operations for the periods presented. Additionally, Forest has separately presented Lone Pine’s assets and liabilities in the Consolidated Balance Sheet as of December 31, 2010. Lone Pine’s assets and liabilities are not presented in Forest’s Consolidated Balance Sheet as of December 31, 2011 due to the spin-off occurring on September 30, 2011. For more information regarding the spin-off see Note 5.
The table below presents the major classes of assets and liabilities included in the discontinued operations classifications within the Consolidated Balance Sheet as of December 31, 2010.
The table below presents the major components of earnings from discontinued operations for the periods presented.
(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION:
The Company's 8½% senior notes due 2014 and 7¼% senior notes due 2019 have been fully and unconditionally guaranteed by a wholly-owned subsidiary of the Company (the "Guarantor Subsidiary"). The Company's remaining subsidiaries (the "Non-Guarantor Subsidiaries") have not provided guarantees. Based on this distinction, the following presents condensed consolidating financial information as of December 31, 2011 and 2010, and for the three years in the period ended December 31, 2011 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Eliminating entries presented are necessary to combine the entities.
CONDENSED CONSOLIDATING BALANCE SHEETS
(In Thousands)
CONDENSED CONSOLIDATING BALANCE SHEETS (Continued)
(In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (Continued)
(In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Continued)
(In Thousands)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Continued)
(In Thousands)
(15) 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 Oil and Gas Reserves
The reserve estimates as of December 31, 2011, 2010 and 2009 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance issued by the Financial Accounting Standards Board effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC's "Modernization of Oil and Gas Reporting" rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.
Proved oil and gas reserves are those 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. Existing economic conditions include the average prices for oil and gas during the twelve month period before the reporting date, 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 oil and gas 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 oil and gas 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 and gas reserves as of December 31, 2011, 2010, and 2009 and changes in its net proved oil and gas 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.
Revisions of previous estimates
In 2011, net negative revisions of 120 Bcfe were primarily a result of the write-off of proved undeveloped locations ("PUD") pursuant to the SEC's five year limitation on PUDs and the write-off of gas reserves associated with a deep gas project in South Louisiana. In 2010, the net negative revisions of 33 Bcfe were primarily the result of performance in existing producing wells. In 2009, the net negative revisions of 384 Bcfe were due to a decrease in the natural gas price used to estimate reserve volumes for that period.
Extensions and discoveries
In 2011, the Company had 301 Bcfe of extensions and discoveries, which were primarily due to successful drilling results in the Texas Panhandle and South Texas. In 2010, the Company had 282 Bcfe of extensions and discoveries, which were primarily due to successful drilling results in the Texas Panhandle and North Louisiana. In 2009, the Company had 510 Bcfe of extensions and discoveries, which were primarily due to successful drilling results in the Texas Panhandle and East Texas / North Louisiana.
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 gas property interests. See Note 2 for a description of these sales.
Aggregate Capitalized Costs
The aggregate capitalized costs relating to oil and gas producing activities were as follows as of the dates indicated:
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, 2011, 2010, and 2009:
____________________________________________
(1)
Includes amounts relating to changes in estimated asset retirement obligations of $3.1 million, $(1.1) million, and $1.1 million recorded during the years ended December 31, 2011, 2010, and 2009, respectively.
Results of Operations from Oil and Gas Producing Activities
Results of operations from oil and gas producing activities for the years ended December 31, 2011, 2010, and 2009 are presented below.
Standardized Measure of Discounted Future Net Cash Flows
Future oil and gas sales are calculated applying the prices used in estimating the Company's estimated proved oil and gas 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 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 oil and gas 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 oil and gas 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 oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%.
Changes in the demand for oil and natural gas, 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.
Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows:
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas 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.
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2010 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, 2010 were $4.38 per MMBtu and $79.81 per barrel, respectively.
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2009 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, 2009 were $3.87 per MMBtu and $61.08 per barrel, respectively.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures.
We have established disclosure controls and procedures to ensure that material information relating to Forest and its consolidated subsidiaries is made known to the Officers who certify Forest's financial reports and the Board of Directors.
Our Chief Executive Officer, H. Craig Clark, and our Chief Financial Officer, Michael N. Kennedy, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this Annual Report on Form 10-K (the "Evaluation Date"). Based on this evaluation, they believe that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms; and (ii) is accumulated and communicated to Forest's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
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 the Exchange Act, Rules 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. Based on our evaluation under the framework in Internal Control-Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control Over Financial Reporting.
There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of Forest Oil Corporation
We have audited Forest Oil Corporation and subsidiaries' internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Forest Oil Corporation and subsidiaries' 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 opinion, Forest Oil Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.
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 and subsidiaries and subsidiaries as of December 31, 2011 and 2010 and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 21, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Denver, Colorado
February 21, 2012
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The names of the executive officers of Forest and their titles, ages, and biographies required by this Item are incorporated by reference to the information set forth under the caption "Executive Officers of Forest" included in Part I, Item 4A of this Annual Report on Form 10-K.
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, 2011 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.
Item 11. Executive Compensation.
Information regarding Forest's compensation of its named executive officers and directors is set forth under the captions "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.
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.
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.
Item 14. Principal Accounting Fees and Services.
Information regarding principal auditor 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.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)
The following documents are filed as part of this report or are incorporated by reference:
i.
Financial Statements:
1. Report of Independent Registered Public Accounting Firm
2. Consolidated Balance Sheets-December 31, 2011 and 2010
3. Consolidated Statements of Operations-Years Ended December 31, 2011, 2010, and 2009
4. Consolidated Statements of Shareholders' Equity-Years Ended December 31, 2011, 2010, and 2009
5. Consolidated Statements of Cash Flows-Years Ended December 31, 2011, 2010, and 2009
6. Notes to Consolidated Financial Statements-Years Ended December 31, 2011, 2010, and 2009
(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 listed in Item 15(b) hereof for a list of those exhibits filed as part of this Annual Report on Form 10-K.
(b)
Index of Exhibits:
*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 Annual Report on Form 10-K.
±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.
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.
________________________________________________________________________________________________________________________
Power of Attorney
The officers and directors of Forest Oil Corporation, whose signatures appear below, hereby constitute and appoint H. Craig Clark, Michael N. Kennedy, Cyrus D. Marter IV, and Victor A. Wind and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this Annual Report on Form 10-K for the year ended December 31, 2011, and any instrument or document filed as part of, as an exhibit to or in connection with any amendment, and each of the undersigned does hereby ratify and confirm as his own act and deed all that said attorneys shall do or cause to be done by virtue thereof.
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.
Index to Exhibits
*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 Annual Report on Form 10-K.
±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.