UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported):  February 11, 2009

FOREST OIL CORPORATION

(Exact name of registrant as specified in its charter)

New York

(State or other jurisdiction of incorporation)

303.812.1400

(Registrant’s telephone number, including area code)

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o    Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o            Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act   (17 CFR 240.13e-4(c))

Item 8.01               Other Events

On February 11, 2009, we issued a press release announcing that we are commencing a private $350 million debt offering.  We are offering to eligible purchasers, subject to market and other conditions, $350 million principal amount of a new series of Senior Notes due 2014.  We intend to use the proceeds of the offering to repay a portion of the outstanding borrowings under our bank credit facilities.  A copy of the press release is filed as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated herein by reference.

The notes will not be registered under the Securities Act of 1933, as amended (the “Securities Act”), or applicable state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state securities laws.  The notes may be resold by the initial purchasers pursuant to Rule 144A and Regulation S under the Securities Act.  The information contained in this Current Report on Form 8-K, including Exhibit 99.1, is neither an offer to sell nor a solicitation of an offer to buy any of the securities in the offering or any other securities of Forest.

In connection with the commencement of the notes offering on February 11, 2009, Forest is providing updated disclosures with respect to Forest, its business strategy, and recent developments, and updating certain disclosures appearing under the headings “Risk Factors” contained in its Annual Report on Form 10-K for the fiscal year ended December 31, 2007 and its quarterly reports on Form 10-Q for the periods ending March 31, 2008, June 30, 2008, and September 30, 2008, and risks described in its Current Reports on Form 8-K.

(i)            Forest Oil Corporation

We are an independent oil and gas company engaged in the acquisition, exploration, development, and production of natural gas and liquids primarily in North America. We were incorporated in New York in 1924, as the successor to a company formed in 1916, and have been a publicly held company since 1969. We currently conduct our operations in three geographical segments and five business units. Our geographical segments include the United States, Canada, and International. Our business units include Western, Eastern, Southern, Canada, and International. We conduct exploration and development activities in each of our geographical segments; however, substantially all of our estimated proved reserves and all of our producing properties are located in North America. Our total estimated proved reserves as of December 31, 2008 were approximately 2,668 billion cubic feet equivalent (“Bcfe”). At December 31, 2008, approximately 87% of our estimated proved reserves were in the United States, approximately 11% were in Canada, and the remainder were in Italy.

Over the last several years, we have implemented a strategy directed at transforming Forest from a predominantly Gulf of Mexico oil and gas producer with international frontier exploration emphasis to a North American onshore development company with numerous lower risk opportunities for production and reserve growth. As part of this transformation, we have made several key acquisitions of properties in our core operational areas while divesting certain non-core assets, including our offshore Gulf of Mexico properties in 2006 and our Alaska properties in 2007. Since the beginning of 2004, we have spent approximately $4.6 billion to acquire oil and gas assets that included approximately 1,682 Bcfe of estimated proved reserves at the date of acquisition. In general, our acquisition program has focused on acquisitions of properties that have substantial development drilling opportunities and undeveloped acreage. Our drilling and recompletion activities have added 1,282 Bcfe of estimated proved reserves over the last five years and our inventory of future drilling locations is at an all-time high as of December 31, 2008. Since 2004, we have also divested non-core oil and gas properties with estimated proved reserves of 705 Bcfe. The following table sets forth changes in our estimated proved reserves over the last five years:

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During 2008, we achieved two important operational goals:

·      Increased estimated proved reserves 26% to 2,668 Bcfe, a record for us; and

·      Increased production 22% to 518 MMcfe/d, a record for us.

Due to significant changes in the overall economy as well as the price for oil and natural gas, we have chosen to significantly reduce our capital expenditures and drilling activity in 2009. Our goal in 2009 is to keep our exploration and development capital spending within our cash flow from operations, while maintaining our estimated proved reserve base and production, protecting against lease expirations and non-consent penalties, and staying focused on cost control.

We plan to devote over one-third of our capital spending in 2009 to horizontal drilling in the Ark-La-Tex and Greater Buffalo Wallow areas. We expect this horizontal drilling to generate rates of return acceptable to us in the current price and cost environment. We also plan to rely almost exclusively on our drilling subsidiary, Lantern Drilling Company (“Lantern”), to drill our wells whenever possible.

We have a divestiture program with an announced intention to sell $450 million to $750 million of non-core properties. Due to the current economic conditions, this program has been delayed. We hope to complete these divestitures by year end 2010. We intend to use the proceeds from these planned divestitures to reduce debt.

By keeping our capital spending within our cash flow from operations, we hope to maintain financial flexibility and sufficient liquidity to maintain our assets and operations until margins on oil and gas production improve. In order to preserve significant borrowing capacity and flexibility under our bank credit facilities, we increased our bank credit facilities from $1.0 billion to $1.8 billion effective May 9, 2008. As of January 31, 2009, we had approximately $400 million available under our bank credit facilities. We intend to use the net proceeds from the notes offering to reduce borrowings under our bank credit facilities. Under the terms of our bank credit facilities, our global borrowing base will be immediately reduced by an amount equal to $0.30 for every $1.00 principal amount of the notes issued. In addition, our global borrowing base will be subject to a redetermination based on our December 31, 2008 proved reserves in March or April 2009.

Hedging is also an important part of our strategy to cushion our exposure to commodity price volatility. As of February 9, 2009, we have hedged, via swaps and collar instruments, approximately 82.9 Bcfe of our estimated 2009 production and approximately 39.8 Bcfe of our estimated 2010 production.

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(ii) Recent developments

As of February 9, 2009, we had natural gas and oil derivatives in place for 2009 and 2010 covering the aggregate average daily volumes and weighted average prices shown below. None of these natural gas and oil derivatives contain knock-out provisions that would cause a derivative to cease to exist at prices below an established threshold.

(1)           10.0 Bbtu/d of natural gas swaps are subject to a written put of $6.00 per MMBtu.

We also have basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX price and the index price at which the natural gas production is sold. As of February 9, 2009, we had basis swaps in place for 2009 and 2010 covering the aggregate average daily volumes and weighted average prices shown below:

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(iii)  Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows, and results of operations, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

Oil and natural gas prices are volatile. Recent declines in commodity prices have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.

Our financial condition, operating results, and future rate of growth depend upon the prices that we receive for our oil and natural gas. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our bank credit facilities and through the capital markets. The amount available for borrowing under our bank credit facilities is subject to a global borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. The recent decline in oil and natural gas prices has adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our global borrowing base. If commodity prices continue to decline in 2009, it will have similar adverse effects on our reserves and global borrowing base. Further, because we have elected to use the full-cost accounting method, we must perform each quarter a “ceiling test” that is impacted by declining prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings. For example, as a result of the dramatic declines in oil and natural gas prices in the second half of 2008, we anticipate that we will record a non-cash ceiling test impairment of approximately $1.5 billion after-tax for the three months and year ended December 31, 2008. The impairment will result in a charge to net earnings, and we expect to record a net loss for 2008. See “—Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.”

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

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The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. Oil spot prices reached historical highs in July 2008, peaking at more than $145 per barrel, and natural gas spot prices reached near historical highs in July 2008, peaking at more than $13 per MMBtu. These prices have declined significantly since that time and may continue to fluctuate widely in the future. The prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:

·      domestic and global supplies, consumer demand for oil and natural gas, and market expectations regarding supply and demand;

·      domestic and worldwide economic conditions;

·      the impact of the U.S. dollar exchange rate on oil and natural gas prices;

·      the proximity, capacity, cost, and availability of oil and natural gas pipelines, processing, gathering, and other transportation facilities;

·      weather conditions;

·      political instability and armed conflicts in oil-producing and gas-producing regions;

·      actions by the Organization of Petroleum Exporting Countries directed at maintaining prices and production levels;

·      the price and availability of imports of oil and natural gas;

·      the impact of energy conservation efforts and the price and availability of alternative fuels; and

·      domestic and foreign governmental regulations and taxes.

These factors make it very difficult to predict future commodity price movements with any certainty. We sell the majority of our oil and natural gas production at current prices rather than through fixed-price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Approximately 75% of our estimated proved reserves at December 31, 2008 were natural gas, and, as a result, our financial results in 2009 will be more sensitive to fluctuations in natural gas prices.

We require substantial capital expenditures to conduct our operations, engage in acquisition activities, and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy.

We require substantial capital expenditures to conduct our exploration, development, and production operations, engage in acquisition activities, and replace our production. Historically, we have funded our capital expenditures through a combination of our cash flows from operations, our bank credit facilities, and debt and equity

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issuances. We also engage in asset sale transactions to fund capital expenditures when market conditions permit us to complete transactions on terms we find acceptable. In 2008, 2007, and 2006, we spent approximately $2.8 billion, $3.0 billion, and $943 million, on capital expenditures, respectively, including approximately $1.4 million, $2.2 billion, and $316 million on property acquisitions, respectively. Our capital expenditures budget for 2009 is approximately $500 to $600 million. Our 2009 budget reflects our intention to finance our capital expenditures with cash flow from operations. Our lower level of planned capital expenditures in 2009, compared with 2008, reflects our expectations of lower future commodity prices and declining service costs in 2009. In addition, we may seek advances under our bank credit facilities to fund some of our 2009 capital and operating expenses. For any large acquisitions or other exceptional expenditures, we expect we would need to access the public or private capital markets or complete additional asset sales. If our revenues and cash flows decrease in the future as a result of a continuation of the decline in commodity prices, however, and we are unable to obtain additional debt or equity financing in the private or public capital markets or access alternative sources of funds in 2009, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to replace our reserves or maintain our production at current levels.

Our future revenues, cash flows, and spending levels are subject to a number of factors, including commodity prices, the level of production from existing wells, and our success in developing and producing new wells. Further, our ability to access funds under our bank credit facilities is based on a global borrowing base, which is subject to periodic redeterminations based on our estimated proved reserves and prices that will be determined by our lenders using the prices prevailing at such time. If the prices for oil and natural gas decline, or if we have a downward revision in estimates of our proved reserves, the global borrowing base may be reduced.

Our ability to access the private and public debt and equity markets and complete future asset monetization transactions is also dependent upon oil and natural gas prices, in addition to a number of factors, some of which are outside our control. These factors include, among others:

·      the value and performance of our debt and equity securities;

·      the credit ratings assigned to our debt by independent rating agencies;

·      domestic and global economic conditions; and

·      conditions in the domestic and global financial markets.

The continuing financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our current bank credit facilities because of the deterioration of the capital and credit markets and our global borrowing base.

The current credit crisis and related turmoil in the global financial systems have had an impact on our business and our financial condition, and we may face challenges if

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economic and financial market conditions do not improve. Historically, we have used our cash flow from operations and borrowings under our bank credit facilities to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. A continuation of the economic crisis could further reduce the demand for oil and natural gas and continue to put downward pressure on the prices for oil and natural gas, which have declined significantly since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows.

We have existing bank credit facilities with lender commitments totaling $1.8 billion and a global borrowing base set at $1.8 billion. The global borrowing base is determined by the lenders periodically and is based on the estimated value of our oil and gas properties using pricing models determined by the lenders at such time. Under the terms of our bank credit facilities, our global borrowing base will be immediately reduced by an amount equal to $0.30 for every $1.00 principal amount of the notes issued. The closing of the notes offering will result in a reduction in our global borrowing base of $105 million. In addition, our bank credit facilities will be subject to a redetermination based on our December 31, 2008 proved reserves in March or April 2009. In the future, we may not be able to access adequate funding under our bank credit facilities as a result of (i) a decrease in our global borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. The recent declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the global borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the global borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.

The current credit crisis makes it difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to existing debt or at all, and reduced and, in some cases, ceased to provide any new funding.

The credit crisis also has impacted the level of activity in the oil and gas property sales market. The lack of available credit and access to capital has limited and will likely continue to limit the parties interested in any proposed asset transactions and will likely reduce the values we could realize in those transactions. We were unable to complete all of our planned asset divestitures in the second half of 2008 due to the distressed market conditions, and we believe that it will be difficult to complete any asset monetization transactions in 2009 on economically attractive terms.

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The distressed economic conditions also may adversely affect the collectability of our trade receivables. For example, our accounts receivable, which totaled $206 million at September 30, 2008, are primarily from purchasers of our oil and natural gas production and other exploration and production companies which own working interests in the properties that we operate. This industry concentration could adversely impact our overall credit risk, because our customers and working interest owners may be similarly affected by changes in economic and financial market conditions, commodity prices, and other conditions. Further, the credit crisis and turmoil in the financial markets could cause our commodity derivative instruments to be ineffective in the event a counterparty were to be unable to perform its obligations or seek bankruptcy protection.

Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required and on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

We have substantial indebtedness and may incur more debt in the future. Our leverage may materially affect our operations and financial condition.

At September 30, 2008, the principal amount of our outstanding consolidated debt was approximately $2.7 billion, including approximately $1.2 billion outstanding under our combined U.S. and Canadian credit facilities. At January 31, 2009, the principal amount of our outstanding consolidated debt was approximately $2.8 billion, including approximately $1.4 billion outstanding under our combined U.S. and Canadian credit facilities. Our level of indebtedness has several important effects on our business and operations; among other things, it may:

·                  require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;

·                  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 due to changes in our debt level or our financial condition;

·                  limit our access to the capital markets;

·                  increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;

·                  impact our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt

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arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;

·                  place us at a disadvantage compared to similar companies in our industry that have less debt; and

·                  and make us more vulnerable to economic downturns and adverse developments in our business.

We may incur more debt in the future. In May 2008, we issued $250 million of additional 71/4% senior notes due 2019 and used the proceeds to fund a portion of the redemption of $265 million of senior notes that matured in June 2008. Also in May 2008, we entered into an amendment to our bank credit facilities with existing and new lenders, which increased the combined commitment amount from $1.0 billion to $1.8 billion and established the global borrowing base at $1.8 billion. As of September 30, 2008, we had $0.6 billion available for borrowings under our bank credit facilities.  A higher level of debt will increase the risk that we may default on our financial obligations.

Our credit and debt agreements contain various restrictive covenants. A failure on our part to comply with the financial and other restrictive covenants contained in our bank credit facilities and the indentures pertaining to our outstanding senior notes could result in a default under these agreements. Any default under our bank credit facilities or indentures could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future. In addition, the global borrowing base included in our bank credit facilities is subject to periodic redetermination by our lenders. A lowering of our global borrowing base could require us to repay indebtedness in excess of the borrowing base.

Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be affected by oil and natural gas prices, financial, business, and domestic and global economic conditions, governmental regulations and environmental regulations, and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

Our use of hedging transactions could result in financial losses or reduce our income.

To reduce our exposure to fluctuations in oil and natural gas prices, we have entered into and expect in the future to enter into derivative instruments (or hedging agreements) for a portion of our oil and natural gas production. Our commodity hedging agreements are limited in duration, usually for periods of two years or less; however, in conjunction with acquisitions, we sometimes enter into or acquire hedges for longer periods. As of February 9, 2009, we had hedged, via commodity swaps and collar instruments, approximately 82.9 Bcfe of our estimated 2009 production and 39.8 Bcfe of our estimated 2010 production. Our hedging transactions expose us to certain risks and financial losses, including, among others:

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·                  the risk that we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions;

·                  the risk that we may hedge too much or too little production depending on how oil and natural gas prices fluctuate in the future;

·                  the risk that there is a change to the expected differential between the underlying price and the actual price received; and

·                  the risk that a counterparty to a hedging arrangement may default on its obligations to Forest.

Our hedging transactions will impact our earnings in various ways. Due to the volatility of oil and natural gas prices, we may be required to recognize mark-to-market gains and losses on derivative instruments as the estimated fair value of our commodity derivative instruments is subject to significant fluctuations from period to period. The amount of any actual gains or losses recognized will likely differ from our period to period estimates and will be a function of the actual price of the commodities on the settlement date of the derivative instrument. For example, for the first two quarterly periods in 2008, we reported unrealized losses on our commodity derivative instruments of $137 million and $329 million, respectively. In contrast, for the third quarter of 2008, we reported unrealized gains on our commodity derivative instruments of $498 million. We expect that commodity prices will continue to fluctuate in the future and, as a result, our periodic financial results will continue to be subject to fluctuations related to our derivative instruments.

Currently, all of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our bank credit facilities. As of February 9, 2009, our primary derivative counterparties included the following lenders and their affiliates: BMO Capital Markets Financing, Inc. (“BMO”), BNP Paribas Securities Corp. (“BNP Paribas”), Barclays Bank PLC (“Barclays”), Credit Suisse, Deutsche Bank AG New York Branch (“Deutsche Bank”), Fortis Capital Corp. (“Fortis”), The Bank of Nova Scotia, Toronto Dominion—(Texas) LLC and The Toronto-Dominion Bank (collectively, “Toronto Dominion”), and Wells Fargo Bank, N.A. (“Wells Fargo”). Our derivative transactions with BMO, Credit Suisse, Fortis, The Bank of Nova Scotia, BNP Paribas and Toronto Dominion accounted for approximately 73 Bcfe, or 88% of our estimated 2009 hedged production, and 32 Bcfe, or 82% of our 2010 estimated hedged production. Our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our bank credit facilities.

Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting to report our oil and gas operations. Under this method, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and

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gas properties may not exceed a “ceiling limit,” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down would not impact cash flow from operating activities, but it would reduce our shareholders’ equity.

Investments in unproved properties, including capitalized interest costs, are also assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized, or is reported as a period expense, as appropriate. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the ceiling test cushion would be reduced.

We also assess the carrying amount of goodwill in the second quarter of each year and at other periods when events occur that may indicate an impairment exists. These events include, for example, a significant decline in oil and gas prices or a decline in our market capitalization.

The risk that we will be required to write down the carrying value of our oil and gas properties, our unproved properties, or goodwill increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. For example, oil and natural gas prices declined significantly throughout the second half of 2008. At December 31, 2008, the spot prices for oil and natural gas were $44.60 per barrel and $5.71 per MMbtu, respectively. Based on these prices, we anticipate that we will record a non-cash ceiling test impairment of approximately $1.5 billion after-tax for the three months and year ended December 31, 2008. The impairment will result in a charge to net earnings, and we expect to record a net loss for 2008. Since that time, the volatility in commodity prices has continued and the conditions in the global economic markets have continued to deteriorate. These and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future and incur additional charges against future earnings. Further, our ceiling test cushion will be subject to fluctuation as a result of any future acquisition and divestiture activities.

Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our estimates.

The proved oil and gas reserve information and the related future net revenues information contained or incorporated by reference in this offering memorandum represent only estimates, which are prepared by our internal staff of engineers. Estimating

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quantities of proved oil and natural gas reserves is a subjective, complex process and depends on a number of variable factors and assumptions. To prepare estimates of economically recoverable oil and natural gas reserves and future net cash flows:

·                  we analyze historical production from the area and compare it to production rates from other producing areas;

·                  we analyze available technical data, including geological, geophysical, production, and engineering data, and the extent, quality, and reliability of this data can vary; and

·                  we must make various economic assumptions, including assumptions about oil and natural gas prices, drilling, operating, and production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the availability of funds.

As a result, these estimates are inherently imprecise. Ultimately, actual production, revenues, taxes, expenses, and expenditures relating to our reserves will vary from our estimates. Any significant inaccuracies in our assumptions or changes in operating conditions could cause the estimated quantities and net present value of the reserves contained or incorporated by reference in this offering memorandum to be different from our estimates. In addition, we may adjust our estimates of proved reserves to reflect production history, actual results, prevailing commodity prices, and other factors, many of which are beyond our control.

You should not assume that any present value of future net cash flows from our producing reserves contained or incorporated by reference in this offering memorandum represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations and, or taxes. At December 31, 2008, approximately 37% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve 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. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

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Our failure to replace our reserves could result in a material decline in our reserves and production, which could adversely affect our financial condition.

In general, our proved reserves decline when oil and natural gas is produced, unless we are able to conduct successful exploitation, exploration, and development activities, or acquire additional properties containing proved reserves, or both. Our future performance, therefore, is highly dependent upon our ability to find, develop, and acquire additional oil and natural gas reserves that are economically recoverable. Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot assure you that our future exploitation, exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, the current economic crisis has adversely impacted our ability to obtain financing to fund acquisitions and has lowered the level of activity and depressed values in the oil and natural gas property sales market. See “—The continuing financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our current bank credit facilities because of the deterioration of the capital and credit markets and our global borrowing base,” for a discussion of the impact of financial market conditions on our access to financing.

Drilling is a high-risk activity and may not result in commercially productive reserves.

We do not always encounter commercially productive reservoirs through our drilling operations. The seismic data and other technologies that we use when drilling wells do not allow us to conclusively determine prior to drilling a well whether oil or natural gas is present or can be produced economically. As a result, we may drill new wells or participate in new wells that are dry wells or are productive but not commercially productive and, as a result, we may not recover all or any portion of our investment in the wells we drill or in which we participate.

The costs and expenses of drilling, completing, and operating wells are often uncertain. The presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling costs to be significantly higher than expected or cause our drilling activities to be unsuccessful or result in the total loss of our investment. Also, our drilling operations may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control, including, among others:

·                  unexpected drilling conditions;

·                  geological irregularities or pressure in formations;

·                  mechanical difficulties and equipment failures or accidents;

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·                  increases in the costs of, or shortages or delays in the availability of, drilling rigs and related equipment;

·                  shortages in labor;

·                  adverse weather conditions;

·                  compliance with environmental and other governmental requirements;

·                  fires, explosions, blow-outs, or surface cratering; and

·                  restricted access to land necessary for drilling or laying pipelines.

We conduct our drilling activities through a wholly owned drilling subsidiary that provides services to us and third parties. The activities conducted by the drilling subsidiary are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks outside of our control, including the factors described above, and the risks associated with conducting drilling activities. Among other things, these risks include the risk of natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases, any of which could result in substantial losses, personal injuries or loss of life, severe damage to or destruction of property, natural resources and equipment, extensive pollution or other environmental damage, clean-up responsibilities, regulatory investigations, and administrative, civil, and criminal penalties, and injunctions resulting in the suspension of our operations. If any of these risks occur, we could sustain substantial losses.

Competition within our industry is intense and may adversely affect our operations.

We operate in a highly competitive environment. We compete with major and independent oil and gas companies in acquiring desirable oil and gas properties and in obtaining the equipment and labor required to develop and operate such properties. We also compete with major and independent oil and gas companies in the marketing and sale of oil and natural gas. Many of these competitors are larger, including some of the fully integrated companies, and have financial, staff, and other resources substantially greater than ours and, or are less leveraged. As a result, these companies may have more access to capital and may be able to pay more for development prospects and producing properties, or evaluate and bid for a greater number of properties and prospects than our financial and staffing resources permit. Also, from time to time, we have to compete with financial investors in the property acquisition market, including private equity sponsors with more funds and access to additional liquidity. Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff, and resources to identify and evaluate properties, available funds, and internal standards for minimum projected return on investment. Commodity prices increased to historic levels in 2008, before declining significantly. As commodity prices increased, so did the cost of equipment, service, and labor in the industry as well as the cost of properties available for acquisition. While commodity prices have dropped significantly since reaching their historic highs, the costs of obtaining necessary equipment, services, and labor have not

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declined in a corresponding fashion, which impacts our cash flows and places us at a disadvantage with companies with greater cash flows and liquidity. In addition, oil and gas producers are increasingly facing competition from providers of non-fossil energy, and government policy may favor those competitors in the future. Many of these competitors have financial and other resources substantially greater than ours. We can give no assurance that we will be able to compete effectively in the future and that our financial condition and results of operations will not suffer as a result.

Our growth depends partly on our ability to acquire oil and gas properties on a profitable basis.

Acquisition of producing oil and gas properties has historically been a key element of maintaining and growing our reserves and production. Competition for these assets has been and will continue to be intense. The success of any acquisition will depend on a number of factors, including, among others:

·                  the acquisition price;

·                  future oil and gas prices;

·                  our ability to reasonably estimate or assess the recoverable volumes of reserves;

·                  rates of future production and future net revenues attainable from reserves;

·                  future operating and capital costs;

·                  inability to promptly integrate the new operations with Forest’s operations;

·                  results of future exploration, exploitation, and development activities on the acquired properties; and

·                  future abandonment and possible future environmental liabilities.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results from an acquisition may vary substantially from those assumed in the purchase analysis, and acquired properties may not produce as expected, or there may be conditions that subject us to increased costs and liabilities including environmental liabilities. See “—The continuing financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our current bank credit facilities because of the deterioration of the capital and credit markets and our global borrowing base,” for a discussion of the impact of the financial market conditions on our access to financing.

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Our international operations may be adversely affected by currency fluctuations and economic and political developments.

We currently have oil and gas properties and operations in Canada, Italy, and South Africa. As a result, we are exposed to the risks of international operations, including political and economic developments, royalty and tax increases, changes in laws or policies affecting our exploration and development activities, and currency exchange risks, as well as changes in the policies of the United States affecting trade, taxation, and investment in other countries.

We have significant operations in Canada. In the first nine months of 2008, the revenues and expenses of such operations represented approximately 15% of our consolidated oil and gas revenues and 18% of our consolidated production costs. The revenues and expenses of these operations are denominated in Canadian dollars. As a result, the profitability of our Canadian operations is subject to the risk of fluctuation in the exchange rates between the U.S. dollar and Canadian dollar. In addition, our Canadian operations may be adversely affected by recent regulatory developments.

The majority of our Canadian operations are located in Alberta, Canada, and in October 2007, the Alberta Government announced a new oil and gas royalty framework. The new framework went into effect on January 1, 2009. Under the new Alberta framework, royalties for conventional oil, natural gas, and bitumen are linked to price and production levels that apply to both new and existing conventional oil and gas activities and oil sands projects. The new framework applies a sliding rate formula to determine conventional oil and natural gas royalties, which is dependent on market prices and production volumes. Royalty rates for conventional oil will range from 0% to 50%. New natural gas royalty rates will range from 5% to 50%. In comparison, under the prior royalty regime, royalty rates ranged from 10% to 35% for conventional oil and from 5% to 35% for natural gas.

We currently conduct drilling and related exploration and development activities in Italy and are conducting related types of activities in South Africa. These activities may be adversely affected by political, economic, and regulatory developments, changes in the local royalty and tax regimes, and currency fluctuations.

Part of our strategy includes drilling in new or emerging plays. As a result, our drilling in these areas is subject to greater risk and uncertainty.

We have an internal group that is responsible for identifying and exploiting exploratory drilling in new or emerging plays. These activities are more uncertain than drilling in areas that are developed and have established production. For example, in April 2008, we announced a natural gas discovery in the Utica Shale, held under lease or farmout, located in the St. Lawrence Lowlands in Quebec, Canada. Our operations in Quebec are still in the early stages and, to date, we have not booked any proved reserves associated with the Utica Shale discovery. Because emerging plays and new formations have limited or no production history, we are less able to use past drilling results to help predict future results. The lack of historical information may result in not being able to

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fully execute our expected drilling programs in these areas or the return on investment in these areas may turn out not be as attractive as anticipated. We cannot assure you that our future drilling activities in Quebec or other emerging plays will be successful, or if successful will achieve the resource potential levels that we currently anticipate based on the drilling activities that have been completed or achieve the anticipated economic returns based on our current cost models.

Our oil and gas operations are subject to various environmental and other governmental laws and regulations that materially affect our operations.

Our oil and gas operations are subject to various U.S. federal, state, and local laws and regulations, Canadian federal, provincial and local laws and regulations, and local and federal laws and regulations in Italy and South Africa. These laws and regulations may be changed in response to economic or political conditions. Matters subject to governmental regulation include the discharge or other release into the environment of wastes and other substances in connection with drilling and production activities, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning our purchases and sales of natural gas, operations, the spacing of wells, and unitization and pooling of properties, and taxation. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions that could delay, limit or prohibit certain of our operations. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies may restrict the rates of flow of oil and gas wells below actual production capacity. Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. The laws in the United States, Canada, Italy, and South Africa regulate, among other things, the production, handling, storage, transportation, and disposal of oil and gas, by-products from oil and gas, and other substances and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. We may not be able to recover some or any of these costs from insurance.

Canada and Italy are signatories to the United Nations Framework Convention on Climate Change and have ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other greenhouse gases (“GHG”). In response to the Kyoto Protocol, the Canadian federal government introduced the Regulatory Framework for Air Emissions (the “Regulatory Framework”) for regulating GHG emissions by establishing mandatory emissions reduction requirements on a sector basis. Sector-specific regulations are expected to come into force in 2010, but the Regulatory Framework is expected to allow emissions trading, which would enable regulated sources of GHG emissions to purchase emissions allowances or emission reduction credits from other sources. Similar GHG emission reduction requirements apply to our operations in Italy. Additionally, GHG regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a

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framework for managing GHG emissions by reducing specified gas emissions, relative to gross domestic product, to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020 and which imposes duties to report. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets. The Canadian federal government proposes to enter into equivalency agreements with provinces that establish a regulatory regime to ensure consistency with the federal plan. The success of any such plan appears to be doubtful in the current political climate, leaving multiple overlapping levels of regulation. The direct and indirect costs of these regulations may adversely affect our operations and financial results.

In addition, the U. S. Congress is considering legislation to reduce emissions of GHGs, and more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, the U.S. Supreme Court’s holding in its 2007 decision, Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act could result in future regulation of GHG emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of GHGs. In July 2008, the United States Environmental Protection Agency released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of GHG emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for GHGs, it indicates that federal regulation of GHG emissions could occur in the near future. While it is not possible at this time to predict how legislation or new regulations that may be adopted in the United States to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.

The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.

The marketability of our production depends in part upon the availability, proximity, and capacity of pipelines, natural gas gathering systems, and processing facilities. Any significant change in market factors affecting these infrastructure facilities, as well as delays in the construction of new infrastructure facilities, could harm our business. 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 or access to gathering systems that impact a substantial amount of our production, it could temporarily have an adverse impact on our cash flow.

We may not be insured against all of the operating risks to which our businesses are exposed.

The exploration, development, and production of oil and natural gas and the activities performed by our drilling subsidiary and gas gathering subsidiary involve risks.

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These operating risks include the risk of fire, explosions, blow-outs, pipe failure, damaged drilling and oil field equipment, abnormally pressured formations, and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures, or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. 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. In accordance with industry practice, 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 Restated Certificate of Incorporation and Bylaws have provisions that discourage corporate takeovers.

Certain provisions of our Restated Certificate of Incorporation and Bylaws and provisions of the New York Business Corporation Law may have the effect of delaying or preventing a change in control. Our directors are elected to staggered terms. Also, our Restated Certificate of Incorporation authorizes our board of directors to issue preferred stock without shareholder approval and to set the rights, preferences, and other designations, including voting rights of those shares as the board may determine. Additional provisions include restrictions on business combinations, the availability of authorized but unissued common stock, and notice requirements for shareholder proposals and director nominations. Also, our board of directors has adopted a shareholder rights plan. If activated, this plan would cause extreme dilution to any person or group that attempts to acquire a significant interest in Forest without advance approval of our board of directors. The provisions contained in our Bylaws and Restated Certificate of Incorporation, alone or in combination with each other and with the shareholder rights plan, may discourage transactions involving actual or potential changes of control.

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Item 9.01               Financial Statements and Exhibits

(d)           Exhibits

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SIGNATURES

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

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INDEX TO EXHIBITS FILED WITH THE CURRENT REPORT ON FORM 8-K

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