Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
THE COMPANY
Forest Oil Corporation and its subsidiaries (Forest or the Company) are engaged in the acquisition and exploitation of, exploration for and development and production of oil and natural gas. The Company was incorporated in New York in 1924, the successor to a company formed in 1916, and has been a publicly held company since 1969. The Company is active in several of the major exploration and producing areas in and offshore the United States. Forest's principal reserves and producing properties are located in the Gulf of Mexico and in Texas, Oklahoma and Wyoming.
The Company operates from production offices located in Lafayette, Louisiana and Denver, Colorado. Its corporate offices are located in Denver, Colorado. On December 31, 1994, Forest had 200 employees, of whom 143 were salaried and 57 were hourly. On March 31, 1995, primarily as a result of a reduction in force, Forest had 175 employees, of whom 117 were salaried and 58 were hourly.
OPERATING STRATEGY
In 1991, Forest adopted its current operating strategy which is focused primarily on acquiring domestic reserves that have significant exploitation potential, increasing production from existing fields through the application of the Company's technical and operating expertise and participating in exploration through farmout arrangements. The Company believes that it has competitive advantages with respect to acquiring and exploiting properties because of its technical and operating expertise, its seismic data base and its ability to operate both onshore and offshore. The Company seeks to acquire interests in properties in which it would have a significant working interest and which it can operate. Since 1991, pursuant to its operating strategy, the Company has acquired estimated proved reserves of approximately 189 BCF of natural gas and 8 million barrels of oil and condensate at an average property acquisition cost of $1.08 per MCFE. (An MCF is one thousand cubic feet of natural gas. MMCF is used to designate one million cubic feet of natural gas and BCF refers to one billion cubic feet of natural gas. MCFE means thousands of cubic feet of natural gas equivalents, using a conversion ratio of one barrel of oil to 6 MCF of natural gas. With respect to oil, the term BBL means one barrel of oil whereas MBBLS is used to designate one thousand barrels of oil.)
During 1994, the Company's activities were directed primarily toward development, exploitation and exploration of properties that were acquired in the latter part of 1993. Acquisitions of proved reserves in 1994 totaled 8.2 BCF of natural gas and 17,000 barrels of oil, a significant decrease compared to the two preceding years. The Company has not changed its strategy with respect to acquisitions, and intends to continue to pursue its strategy of acquiring additional reserves which satisfy its investment criteria and capital constraints. Forest continues to evaluate potential acquisitions, as well as various types of business combinations and joint ventures.
The Company's operating strategy also includes exploitation activities in the areas of reservoir management and development drilling. Reservoir management involves the effort to enhance value by a combination of reduced costs and the use of such techniques as workovers to increase hydrocarbon recovery. The Company engages in development drilling for additional reserves that offset existing production with the objective of either increasing the density in which wells are drilled or extending reservoirs. The Company believes that it can increase production from, and otherwise enhance the value of, existing fields by utilizing its technical expertise to undertake selective workovers, recompletions and development drilling. Such projects undertaken in 1994 resulted in net daily production increases of approximately 12,263 MCF and 220 barrels of oil and condensate, based upon capacity increases immediately after stabilization of production. Such results are not necessarily indicative of anticipated future results of the Company's workover and development projects.
The Company participates in exploration activities through selective drilling for its own account, as well as through farmout arrangements. During 1994 the Company undertook exploratory projects for its own account
which resulted in net daily production increases of approximately 12,920 MCF and 439 barrels of oil and condensate, based upon capacity increases immediately after stabilization of production. Such results are not necessarily indicative of anticipated future results of the Company's exploration projects.
Farmouts enable Forest to participate in its exploration prospects without incurring additional exploration costs, although with a reduced ownership in each prospect. During 1994, the Company entered into farmout agreements covering 15 prospects. For further information concerning the Company's farmout activity, see Item 2.



ITEM 2. PROPERTIES
Forest's principal reserves and producing properties are oil and gas properties located in the Gulf of Mexico and in Texas, Oklahoma, and Wyoming.
RESERVES
Information regarding the Company's proved and proved developed oil and gas reserves and the standardized measure of discounted future net cash flows and changes therein is included in Note 16 of Notes to Consolidated Financial Statements.
Since January 1, 1994, Forest has not filed any oil or natural gas reserve estimates or included any such estimates in reports to any Federal or foreign governmental authority or agency, other than the Securities and Exchange Commission (SEC), the MMS and the Department of Energy (DOE). The reserve estimate report filed with the MMS related to Forest's Gulf of Mexico reserves and there were no differences between the reserve estimates included in the MMS report, the SEC report, the DOE report and those included herein, except for production and additions and deletions due to the difference in the "as of" date of such reserve estimates.
PRODUCTION
The following table shows net oil and natural gas production for Forest and its wholly-owned subsidiaries for the years ended December 31, 1994, 1993 and 1992:
AVERAGE SALES PRICES AND PRODUCTION COSTS PER UNIT OF PRODUCTION
The following table sets forth the average sales prices per MCF of natural gas and per barrel of oil and condensate and the average production cost per equivalent unit of production for the years ended December 31, 1994, 1993 and 1992 for Forest and its wholly-owned subsidiaries:
PRODUCTIVE WELLS
The following summarizes total gross and net productive wells of the Company and its wholly-owned subsidiaries at December 31, 1994, all of which are in the United States:
DEVELOPED AND UNDEVELOPED ACREAGE
Forest and its wholly-owned subsidiaries held acreage as set forth below at December 31, 1994 and 1993. A majority of the developed acreage is subject to a mortgage lien securing either the Company's bank indebtedness or its nonrecourse secured debt. A portion of the developed acreage is also subject to production payments. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 4 and 5 of Notes to Consolidated Financial Statements.
During 1994, the Company's gross developed acreage increased approximately 9% and net developed acreage increased 13%, primarily as a result of producing property acquisitions. The Company's gross and net undeveloped acreage decreased 35% and 33%, respectively, primarily due to reductions in acreage as a result of reclassifications to developed acreage, lease expirations and the Company's decision not to renew certain leases which were located primarily offshore Louisiana and in Texas.
Approximately 49% of the Company's total net undeveloped acreage is under leases that have terms expiring in 1995, if not held by production, and another approximately 9% of net undeveloped acreage will expire in 1996 if not also held by production.
DRILLING ACTIVITY
Forest and its wholly-owned subsidiaries owned interests in net exploratory and net development wells for the years ended December 31, 1994, 1993 and 1992 as set forth below. This information does not include wells drilled under farmout agreements.
A net development well drilled in Canada in 1992 was completed prior to the September 30, 1992 sale of Canadian operations to CanEagle. This well, in which the Company's ownership interest was .2, was included in properties sold.
FARMOUT AGREEMENTS
Forest entered into farmout agreements with respect to 15 exploration prospects during 1994, including two prospects related to an exploration agreement entered into in 1993. Under these agreements, outside parties undertake exploration activities using prospects owned by Forest. This enables the Company to participate in the exploration prospects without incurring additional capital costs, although with a substantially reduced ownership interest in each prospect. Seven of the farmouts cover onshore prospects and eight cover prospects located in the Gulf of Mexico.
Four of the prospects were drilled during 1994, resulting in two properties capable of producing, both of which are in the same prospect, two dry holes and one well that is currently being tested. Forest retained overriding royalty interests in the 15 prospects ranging from 1.6% to 9.4% before payout, increasing up to a 33.3% net working interest after payout. Five additional wells reached total depth in 1995, resulting in one property capable of
production, one dry hole and three wells currently being tested. The Company anticipates that four of the remaining six undrilled farmouts will be drilled during 1995.
During 1994, the Company entered into an exploration agreement with a third party, covering ten blocks (approximately 50,000 acres) leased by the Company in the Gulf of Mexico, offshore Texas and Louisiana. Under the terms of the agreement, the third party will utilize 3-D seismic to evaluate and identify potential drilling opportunities over an 18-month period. Upon completion of the evaluations, the third party must elect to either commence drilling at no expense to the Company, or return the leases. The Company retains the option to back-in for a 35% working interest at casing point with no payout requirements or to retain a 12.5% overriding royalty. In 1995 the third party drilled one of these prospects, which is currently being tested, and continues to evaluate the remaining acreage.
PRESENT ACTIVITIES
At December 31, 1994, Forest and its wholly owned subsidiaries had two development wells and one exploratory well that were in the process of being drilled. One of these two development wells was determined to be productive in January, 1995 and the other was a dry hole. The exploratory well reached total depth during January 1995. It was subsequently sidetracked and is currently being tested. There were also three wells being drilled under farmout agreements at year-end, all of which are currently being tested as discussed above.
DELIVERY COMMITMENTS
At December 31, 1994 Forest and its wholly-owned subsidiaries were obligated to deliver, or to make cash settlement with respect to, approximately 19.1 BCF of natural gas and 261,000 barrels of oil under the terms of volumetric production payments. The delivery commitments cover approximately 26% and 9% of the estimated net proved reserves of natural gas and oil, respectively, attributable to the subject properties. The production payments are nonrecourse to other properties owned by the Company. The Company is further obligated to deliver approximately .9 BCF of natural gas under existing long-term contracts. For further information concerning the Company's volumetric production payment agreements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 5 and 16 of Notes to Consolidated Financial Statements.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
The Company had two natural gas sales contracts with Columbia Gas Transmission Corp. (Transmission), a subsidiary of Columbia Gas System (CGS). On July 31, 1991, CGS and Transmission filed Chapter 11 bankruptcy petitions with the United States Bankruptcy Court for the District of Delaware. Both contracts have been rejected pursuant to the bankruptcy proceedings. The Company has filed a proof of claim in the bankruptcy proceeding consisting of a secured claim of $1,600,000 based on Louisiana vendor lien laws and an unsecured claim relating to the rejection of the contracts. The secured claim arises from Transmission's failure to pay the contract price for a period of time prior to rejection of the contracts. The unsecured claim was calculated on an undiscounted basis and without any assumption of mitigation of damages through spot market sales. No prediction can be given as to when or how these matters will ultimately be concluded.
On April 13, 1995 Forest sold to a bank a participation interest in Forest's claim evidenced by that certain proof of claim dated March 16, 1992 filed by Forest on March 17, 1992 against Transmission in connection with the Chapter 11 proceeding described above. Consideration received consisted of a $4,000,000 nonrecourse loan, in exchange for which the bank will receive, solely from the proceeds of the bankruptcy claim, an amount equal to the loan principal plus accrued interest at 16.5% per annum plus 25% of the excess, if any, of the proceeds over the loan principal and interest. The Company may, under certain conditions, limit the overall cost of financing to 23.5% per annum by exercising its option to repurchase the bank's interest in the bankruptcy claim prior to receipt of any proceeds of the claim.
The Company, in the ordinary course of business, is a party to various other legal actions. In the opinion of management, none of these actions, including those discussed above, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, liquidity or results of operations.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
ITEM 4A. EXECUTIVE OFFICERS OF FOREST
The following information with respect to the executive officers of Forest is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
ITEM 4B. DIRECTORS OF FOREST
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Forest Oil Corporation has one class of common equity securities outstanding. The Common Stock, par value $.10 per share, has one vote per share. During 1993, each share of the Class B Stock, par value $.10 per share, which had 10 votes per share, was reclassified into 1.1 shares of Common Stock pursuant to a vote of the shareholders. In the event of dissolution, liquidation or insolvency, holders of Common Stock share ratably in the net assets of Forest, subject to the liquidation rights of the holders of the $.75 Convertible Preferred Stock.
The Company also has outstanding Warrants to purchase shares of its Common Stock. Each Warrant entitles the holder to purchase one share of Common Stock at a price of $3.00, is non-callable and expires on October 1, 1996.
As of March 31, 1995, 28,250,647 shares of Common Stock were held by 2,060 recordholders and 1,244,715 Warrants were held by 80 recordholders.
Subject to the prior right of the holders of Forest's $.75 Convertible Preferred Stock, the only restrictions on its present or future ability to pay dividends are (i) the provisions of the New York Business Corporation Law (NYBCL), (ii) certain restrictive provisions in the Indenture executed in connection with Forest's 11 1/4% Senior Subordinated Notes due September 1, 2003 pursuant to which the Company is currently prohibited from paying any cash dividends other than on its $.75 Convertible Preferred Stock, and (iii) the Company's Credit Agreement dated December 1, 1993 with The Chase Manhattan Bank (National Association), as agent, under which the Company is restricted in amounts it may pay as dividends (other than dividends payable in common stock). Under the dividend restrictions in the Credit Agreement, the Company is prohibited from paying cash dividends on its $.75 Convertible Preferred Stock after the February 1, 1995 dividend. While these restrictions are effective, subsequent dividends, when and as declared, will be paid in shares of Forest Oil Corporation Common Stock. There is no assurance that Forest will pay any dividends. For further information on Forest's ability to pay dividends on its Common Stock and $.75 Convertible Preferred Stock, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 4, 7 and 8 of Notes to Consolidated Financial Statements.
The Company has one class of preferred stock outstanding. Annual dividends on the $.75 Convertible Preferred Stock are cumulative and are payable quarterly each February 1, May 1, August 1 and November 1, when and as declared. Dividends may be paid in cash or, at the Company's election, in shares of Common Stock or in a combination of cash and Common Stock. As described above, the Company is prohibited from paying cash dividends on its $.75 Convertible Preferred Stock after the February 1, 1995 dividend, due to restrictions contained in the Credit Agreement with its lending banks. While these restrictions are effective, subsequent dividends, when and as declared, will be paid in shares of Forest Oil Corporation Common Stock.
Whenever dividends on the $.75 Convertible Preferred Stock have not been paid, the amount of the deficiency, plus an amount equal to the accumulated dividend for the then current quarterly dividend period, must be fully paid, or declared and set apart for payment, before any dividend may be declared and paid or set apart for payment upon the Common Stock, except for dividends paid in shares of Common Stock.
Whenever $.75 Convertible Preferred Stock dividends are in arrears in an amount equivalent to six full quarterly dividends, the holders of the $.75 Convertible Preferred Stock, voting separately as a class and with one vote per share, will have the right to elect two directors. If two consecutive dividend payments are in arrears, the holder of each share of $.75 Convertible Preferred Stock will be entitled to a penalty conversion right enabling such holder to convert each such share, plus accumulated dividends, into a share of Common Stock during a two-day period 30 days after the second dividend payment date at a conversion price of 75% of the average of the last reported sales prices of the Common Stock during the period from such second dividend payment date to five trading days prior to the conversion date.
The holder of each share of $.75 Convertible Preferred Stock has the right to convert each such share into 3.5 shares of Common Stock at any time. The conversion rate is subject to adjustment in certain events.
The $.75 Convertible Preferred Stock may be redeemed at the option of the Company, in whole or in part, upon notice duly given, at any time after the earlier of (i) July 1, 1996, and (ii) the date on which the last reported sales price of the Common Stock will have been $7.50 or higher for at least 20 of the prior 30 trading days, at the redemption prices set forth below, in each case with an amount equal to dividends (whether or not declared) accrued to the date fixed for redemption and remaining unpaid:
As of March 31, 1995, 2,880,973 shares of $.75 Convertible Preferred Stock were held by 92 recordholders.
Forest's Common Stock is traded on the National Market System of the National Association of Securities Dealers, Inc., Automated Quotation System (NASDAQ/NMS). The High and Low sales prices of the Common Stock for each quarterly period of the years presented as reported by the NASDAQ/NMS are listed in the chart below. The Class B Stock was not traded in any public trading market. There were no dividends on Common Stock or Class B Stock in 1993, 1994 or in the first quarter of 1995.
On March 31, 1995, the last reported sales price of the Common Stock as quoted on the NASDAQ/NMS was $2-5/16 per share.
The Warrants are traded on the NASDAQ/NMS. The High and Low sales prices of the Warrants for each quarterly period of the years presented as reported by the NASDAQ/NMS are listed in the chart below.
On March 31, 1995, the last reported sales price of the Warrants as quoted on the NASDAQ/NMS was $3/8 per Warrant.
The $.75 Convertible Preferred Stock is traded on the NASDAQ/NMS. The High and Low sales prices of the $.75 Convertible Preferred Stock for each quarterly period of the years presented as reported by the NASDAQ/NMS are listed in the chart below.
On March 31, 1995, the last reported sales price of the $.75 Convertible Preferred Stock as quoted on the NASDAQ/NMS was $9-1/8 per share.
In October 1993, the Board of Directors adopted a shareholders' rights plan. The Company issued a dividend of a preferred stock purchase right (the "Rights") on each outstanding share of Common Stock of the Company, which, after the Rights become exercisable, entitles the holder to purchase 1/100th of a share of a newly issued series of the Company's preferred stock at a purchase price of $30 per 1/100th of a preferred share, subject to adjustment. The Rights expire on October 29, 2003 unless extended or redeemed earlier. The Rights will become exercisable (unless previously redeemed or the expiration date of the Rights has occurred) following a public announcement that a person or group (an "Acquiring Person") has acquired 20% or more of the Common Stock or has commenced (or announced an intention to make) a tender offer or exchange offer for 20% or more of the Common Stock. In certain circumstances each holder of Rights (other than an Acquiring Person) will have the right to receive, upon exercise, (i) shares of Common Stock of the Company having a value significantly in excess of the exercise price of the Rights, or (ii) shares of Common Stock of an acquiring company having a value significantly in excess of the exercise price of the Rights.
ITEM 6.

ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
The following table sets forth selected data regarding the Company as of and for each of the years in the five-year period ended December 31, 1994. This data should be read in conjunction with Item 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the Company's Consolidated Financial Statements and Notes thereto.
RESULTS OF OPERATIONS
NET EARNINGS (LOSS). The Company's net loss was $81,843,000 in 1994 compared to a net loss of $21,213,000 in 1993 and net earnings of $7,298,000 in 1992. There would have been a net loss of $16,745,000 in 1992 excluding the effects of the settlement of gas contract litigation with ONEOK Inc. (the ONEOK settlement). Earnings from operations (consisting of total revenue less oil and gas production expense and expensed general and administrative costs) increased in 1994 compared to 1993 as a result of increased natural gas production from acquisitions made throughout 1993; however, this increase was more than offset by a $58,000,000 writedown of the book value of the Company's oil and gas properties due to a ceiling test limitation and a charge of $13,990,000 to reflect the cumulative effects of a change in the Company's method of accounting for oil and gas sales from the sales ("takes") method to the entitlements method. Earnings from operations increased in 1993 compared to the 1992 results (excluding the effects of the ONEOK settlement) as a result of the acquisition of properties; however, this increase was more than offset by higher depreciation and depletion expense, an extraordinary loss of $10,735,000 (net of tax benefit of $4,652,000) recorded as a result of the redemption or purchase of all of the Company's 12 3/4% Senior Secured Notes and long-term subordinated debt and a charge of $1,123,000 to reflect the cumulative effects of changes in accounting principles related to postretirement benefits and income taxes.
The Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994. As a result, earnings from operations for 1994 increased by $3,584,000. Earnings from operations for 1993 and 1992, on a pro forma basis, would have been higher by $5,393,000 and $8,868,000, respectively, as a result of this change in accounting method. The 1993 and 1992 amounts presented herein are not required to be restated to show the effects of this change.
The ONEOK settlement in 1992 had a significant impact on the Company's reported revenue, expense and net earnings. A summary of the Company's income and expenses for 1992, before and after the amounts recorded as a result of the ONEOK settlement, is as follows:
The inclusion of the effects of the ONEOK settlement in a discussion of the Company's results of operations distorts the trends which would otherwise be reported. In the discussion which follows, results for 1992 exclude the effects of the ONEOK settlement in order to more meaningfully compare and discuss the Company's results of operations for 1994, 1993 and 1992.
REVENUE. Total revenue increased 10% to $115,947,000 in 1994 from $105,148,000 in 1993, and increased 39% in 1993 from $75,645,000 in 1992.
Oil and gas sales increased to $114,541,000 from $102,883,000, or by approximately 11%, in 1994 compared to 1993 due primarily to increased natural gas production from properties acquired throughout 1993 and the effects of the change in method of accounting for oil and gas sales, partially offset by normal production declines. In 1994, natural gas production volumes were up 17% compared to 1993 while oil production volumes were 3% higher. The increase in revenue attributable to increased production was partially offset by a 13% decrease in the average sales price for oil. The average sales price for natural gas in 1994 did not differ significantly from the 1993 price.
Oil and gas sales increased to $102,883,000 from $76,847,000, or by approximately 34%, in 1993 compared to 1992 due primarily to increased production from newly-acquired properties and an 11% increase in the average sales price for natural gas. In 1993, oil production volumes were up 3% and natural gas production volumes were up 41% compared to 1992. The increase in revenue attributable to the increased production was partially offset by a 6% decrease in the average sales price for oil.
The production volumes and average sales prices for the years ended December 31, 1994, 1993 and 1992 for Forest and its wholly-owned subsidiaries were as follows:
Natural gas delivered pursuant to volumetric production payment agreements and other long-term fixed price contracts represented approximately 35% of total production in 1994 versus 46% in 1993 and 33% in 1992. In recent years, the industry trend has been for more natural gas to be sold on the spot market as long-term contracts expire. The overall increase experienced by Forest in natural gas sold under long-term fixed price contracts over the three year period presented herein was the result of the Company entering into volumetric production payments.
Miscellaneous net revenue of $1,406,000 in 1994 included income from the sale of miscellaneous pipeline systems and equipment and the reversal of an accounts receivable reserve, partially offset by a reserve for settlement of a royalty dispute and a payment of deferred maintenance costs of a real estate complex used for general business purposes. Miscellaneous net revenue of $2,265,000 in 1993 included $1,380,000 of interest income on short-term investments and an adjustment to reduce accrued severance taxes based on discussions with the applicable state taxing authorities. The net expense of $1,202,000 in 1992 was primarily attributable to a $926,000 provision for future rent payments on vacated office space.
OIL AND GAS PRODUCTION EXPENSE. Oil and gas production expense increased 15% to $22,384,000 in 1994 compared to $19,540,000 in 1993 due primarily to increased natural gas production as a result of property acquisitions throughout 1993, partially offset by a decrease in workover expenses and a general decrease in expenses due to the sale of properties. Oil and gas production expense increased 37% to $19,540,000 in 1993 compared to $14,276,000 in 1992, due primarily to increased production from newly acquired properties and increased workover expense. In 1994 and 1993, production expense was approximately $.39 on an MCFE basis compared to $.38 in 1992.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense decreased 7% to $11,166,000 in 1994 compared to $12,003,000 in 1993. Decreases in salaries, wages and burden from the termination of executives and middle level managers and increases in production operation credits were partially offset by increases in insurance and office and storage rental expenses. General and administrative expense for 1993 was $12,003,000 compared to $12,088,000 in 1992. Increases attributable to severance and employee relocation costs and the effects of the postretirement medical benefit accrual in 1993 were more than offset by lower office and storage rentals and lower professional services expense. The capitalization rate remained relatively constant from 1992 to 1994.
Total overhead costs, including amounts related to exploration and development activities, were $18,719,000 in 1994, $19,561,000 in 1993 and $19,237,000 in 1992. Excluding the severance and employee relocation costs in 1993 described below, total overhead costs were approximately 8% higher in 1994 than in 1993. This increase is primarily due to an increase in storage rentals and higher insurance expense attributable to a larger asset base, partially offset by a decrease in salaries, wages and burden from the termination of executives and middle level managers as described below. The increase in 1993 from 1992 was only 2% despite charges amounting to $2,300,000 for severance and employee relocation costs and $480,000 for postretirement medical benefits; without these charges, total overhead costs would have decreased by approximately 13% in 1993 compared to 1992. Severance and employee relocation costs of approximately $2,300,000 in 1993 resulted from the termination of 10 executives and middle level managers and a loss incurred on an employee's former residence in accordance with the Company's relocation policy. The following table summarizes the total overhead costs incurred during the periods:
RETIREMENT BENEFITS FOR EXECUTIVES AND DIRECTORS. In December 1990, the Company entered into retirement agreements with seven executives and directors ("Retirees") pursuant to which the Retirees will receive supplemental retirement payments totalling approximately $1,127,700 per year through 1996, $1,087,400 in 1997, $938,400 in 1998 and approximately $740,400 per year in 1999 and 2000. The liability to the Retirees was recorded in 1990 and 1991.
INTEREST EXPENSE. Interest expense of $26,773,000 increased $3,044,000 or 13% compared to 1993 due to higher loan balances as a result of recent capital spending. Interest expense of $23,729,000 in 1993 decreased $4,071,000 or 15% compared to 1992, primarily due to redemptions or purchases of certain of the Company's subordinated debentures and 12 3/4% Senior Secured Notes in 1993, partially offset by the interest expense incurred in connection with the Company's new 11 1/4% Senior Subordinated Notes.
DEPRECIATION AND DEPLETION EXPENSE. Depreciation and depletion expense increased 8% to $65,468,000 in 1994 from $60,581,000 in 1993 due to increased production in the 1994 period as a result of property acquisitions. Depreciation and depletion expense increased 30% to $60,581,000 in 1993 from $46,624,000 in 1992 due to increased production in the 1993 period as a result of property acquisitions and workovers. The depletion rate was $1.13 per MCFE for U.S. production in 1994 compared to corresponding rates of $1.19 for U.S. production in 1993 and $1.21 for U.S. production and $1.19 for Canadian production in 1992.
IMPAIRMENT OF OIL AND GAS PROPERTIES. The Company recorded a writedown of its oil and gas properties of $58,000,000 in 1994 due primarily to a decrease in spot market prices for natural gas. The Company could have chosen to lessen or completely eliminate the need for a writedown by entering into financial derivatives (swaps) and locking in future natural gas prices. The Company would have had to contract a significant portion of its natural gas reserve base to avoid the entire writedown. Company management decided not to enter into such contracts because it believes the natural gas market is now at a cyclical low, and such arrangements would ultimately be detrimental to the Company's shareholders. In addition, the Company considered but chose not to adopt successful efforts accounting. It is management's belief that full cost accounting remains the most appropriate method of accounting for the Company's current mix of operations, despite the quarterly ceiling test requirement.
Additional writedowns of the full cost pool may be required if prices decrease, undeveloped property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any.
The average Gulf Coast spot price received by the Company for natural gas declined from $1.77 per MCF at December 31, 1994 to $1.59 per MCF at April 1, 1995. The West Texas Intermediate price for crude oil increased from $15.50 per barrel at December 31, 1994 to $17.25 per barrel at April 1, 1995. Based on April 1, 1995 prices the standardized measure of discounted future net cash flows, exclusive of amounts attributable to volumetric production payments, would have been approximately $193,600,000 at December 31, 1994.
CHANGES IN ACCOUNTING
The Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994. Under the sales method previously used by the Company, all proceeds from production credited to the Company were recorded as revenue until such time as the Company had produced its share of related reserves. Under the entitlements method, revenue is recorded based upon the Company's share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced.
Under the entitlements method, the Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue. The Company believes that the entitlements method is preferable because it allows for recognition of revenue based on the Company's actual share of jointly owned production and provides a better matching of revenue and related expenses.
The cumulative effect of the change for the periods through December 31, 1993, was a charge of $13,990,000. The effect of this change on 1994 was an increase in earnings from operations of $3,584,000 and an increase in
production volumes of 1,555,000 MCF. There were no related income tax effects in 1994. As the Company adopted this change in the fourth quarter of 1994, previously reported 1994 quarterly information has been restated to reflect the change effective January 1, 1994. See Note 15 for restated selected quarterly financial data.
Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," (SFAS No. 106) required the Company to accrue expected costs of providing postretirement benefits to employees and the employees' beneficiaries and covered dependents. The Company adopted the provisions of SFAS No. 106 in the first quarter of 1993. The estimated accumulated postretirement benefit obligation as of January 1, 1993 was approximately $4,822,000. This amount, reduced by applicable income tax benefits, was charged to operations in the first quarter of 1993 as the cumulative effect of a change in accounting principle. The annual net postretirement benefit cost (included in total overhead costs) was approximately $510,000 for 1994 and $483,000 for 1993.
Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," (SFAS No. 109), required the Company to adopt the liability method of accounting for income taxes. The Company adopted such method on a prospective basis as of January 1, 1993 and, as such, prior periods have not been restated. The cumulative effect of adopting SFAS No. 109 as of January 1, 1993 resulted in a reduction of the net amount of deferred income taxes recorded as of December 31, 1992 of approximately $2,060,000. This amount was credited to operations in the first quarter of 1993 as the cumulative effect of a change in accounting principle.
LIQUIDITY AND CAPITAL RESOURCES
RECENT DEVELOPMENTS On April 17, 1995, the Company signed letters of intent with The Anschutz Corporation (Anschutz) and with Joint Energy Development Investments Limited Partnership (JEDI), an affiliate of Enron Corp., in each case as described below.
The Anschutz letter of intent contemplates that Anschutz will purchase 18,800,000 shares of the Company's common stock and shares of newly-issued preferred stock that are convertible into 6,200,000 additional shares of common stock for a total consideration of $45,000,000, or $1.80 per share. The preferred stock will have a liquidation preference and will receive dividends ratably with the common stock. The investment will be made in two closings. In the first closing, expected to occur in late April 1995, Anschutz will loan the Company $9,900,000 for a term of 9 months. The loan will bear interest at 8% per annum for 16 weeks and at 12.5% per annum thereafter. The loan will be secured by unencumbered oil and gas properties owned by the Company, the preferred stock of Archean Energy Ltd. and certain other assets acceptable to Anschutz. The loan may be converted into 5,500,000 shares of Forest's common stock at Anschutz's election, but the loan must be so converted at the second closing. At the second closing, expected to occur by July 1995 following receipt of shareholder approval of the transactions then contemplated by the letters of intent, Anschutz will purchase 13,300,000 shares of common stock and the convertible preferred stock. In connection with this purchase, Anschutz will agree to certain voting, acquisition, and transfer limitations regarding shares of common stock for five years after the second closing, including (a) a limit on voting, subject to certain exceptions, that would require Anschutz to vote all shares of common stock acquired by Anschutz in the transaction in excess of an amount equal to 19.99% of the shares of common stock then outstanding in the same proportion as all other shares of common stock are voted, (b) a limit on the number of persons associated with Anschutz that may at any time be elected as directors of the Company and (c) a limit on the acquisition of additional shares of common stock by Anschutz (whether pursuant to the exercise of the $2.10 warrants or the option received from JEDI, each as described below, or otherwise), subject to certain exceptions, that would prohibit any acquisition by Anschutz that would result in Anschutz owning 40% or more of the shares of common stock then issued and outstanding. While the foregoing limitations are in effect, Anschutz will have a minority representation on the board of directors.
The JEDI letter of intent contemplates that, at the second closing referred to above, Forest and JEDI will restructure JEDI's existing loan currently having a principal balance of approximately $62,100,000. In exchange for certain warrants referred to below, JEDI will relinquish the net profits interest that it holds in certain Forest properties and will reduce the interest rate relating to the loan. As a result of the loan restructuring and the issuance of the warrants, the Company anticipates a reduction of the recorded amount of the related liability to approximately $45,000,000 and a reduction of interest expense of approximately $2,100,000 per annum. In addition, beginning 18 months after the second closing, the Company may prepay the loan at any time and may tender its interest in the underlying properties in full satisfaction of the loan.
The JEDI letter of intent also contemplates that, at the second closing, JEDI will receive warrants to purchase 11,250,000 shares of the Company's common stock for $2.00 per share and warrants to purchase 19,444,444 shares of common stock at $2.10 per share. The $2.00 warrants expire on the earlier of either the payment in full of the JEDI loan or December 31,2002, but no sooner than 18 months after the Second closing, except that the Company may terminate the warrants at any time beginning 18 months after the second closing if the average closing price of the common stock for 90 days preceding the termination is in excess of $2.50 per share. For the first 18 months after the second closing, the $2.00 warrants may be exercised only on the dates and in the respective numbers of shares required to be delivered by JEDI to Anschutz pursuant to the exercise of the option granted by JEDI to Anschutz, as described below. The $2.10 warrants are exercisable during the first 18 months after the second closing, subject to extension in certain circumstances to 36 months after the second closing. The letters of intent also contemplate that, at the second closing, JEDI will assign to Anschutz the $2.10 warrants and will grant to Anschutz an option to purchase up to 11,250,000 shares of common stock during the first 18 months after the second closing.
The letters of intent require the Company to pay Anschutz and JEDI certain fees and expenses in connection with the letters of intent and the transactions contemplated thereby in certain circumstances. The Anschutz letter of intent requires the Company to pay to Anschutz a fee (called a subsequent event fee) of up to $2,500,000 upon the occurence of certain events prior to the second closing (or, if the second closing does not occur, April 17, 1996), such as a merger, consolidation or
other business combination between the Company and a person other than Anschutz. In the Anschutz letter of intent, the Company has agreed not to solicit proposals for transactions that would require the Company to pay a subsequent event fee and to keep Anschutz generally informed regarding the receipt and disposition by the Company of proposals regarding such transactions made by other persons.
The transactions contemplated by the letters of intent are subject to, among other things, the preparation and execution of definitive documentation satisfactory to the parties and to the approval of Forest's board of directors and certain of its creditors. The purchase by Anschutz of common stock at the second closing, the restructure of JEDI's existing loan and the transactions between Anschutz and JEDI described above are also subject to, among other things, the prior approval of Forest's shareholders and Hart-Scott-Rodino clearance. While the Company's short-term and long-term liquidity would be significantly improved by the conclusion of the transactions described above, and although management believes the conditions to the closing of the transactions can be satisfied, there can be no assurance that the transactions will close on the terms and on the dates referred to above, or at all.
SHORT-TERM LIQUIDITY. During 1994 and the first quarter of 1995, the Company's operating cash flows and working capital were adversely affected by a severe industry-wide decline in the price of natural gas. The prices the Company receives for its future oil and natural gas production will significantly impact future operating cash flows. No prediction can be made as to the prices the Company will receive for its future oil and gas production.
Since December 31, 1994, the Company has taken steps and committed to certain actions to address its short-term liquidity needs, including the recent developments described above. Key short-term actions taken and committed to are set forth below.
The Company has reduced its budgeted general and administrative expenditures for 1995 principally through a workforce reduction in March 1995. As a result, total overhead for 1995 is expected to decrease by approximately $4,000,000 compared to 1994 or by approximately 20%.
In response to current market conditions, the Company has reduced its budgeted capital expenditures to those required to maintain its producing oil and gas properties as well as certain essential development, drilling and other activities. The Company's 1995 budgeted expenditures for exploration and development are approximately $5,700,000, and $12,300,000, respectively, including capitalized overhead of $2,300,000 and $3,600,000, respectively. The planned levels of capital expenditures could be further reduced if the Company experiences lower than anticipated net cash provided by operations or other liquidity needs.
The Company has a secured credit facility (the Credit Facility) with The Chase Manhattan Bank, NA. (Chase) as agent for a group of banks. Under the Credit Facility, the Company may borrow up to $17,500,000 for acquisition or development of proved oil and gas reserves and up to $32,500,000 for working capital and general corporate purposes, subject to semi-annual redetermination at the banks' discretion. The total borrowing capacity of the Company under the Credit Facility is $50,000,000. In March 1995, the banks completed their most recent semi-annual redetermination of the Credit Facility and advised the Company that the maximum borrowing capacity would be maintained at $50,000,000. However, the amount of the maximum borrowings under the Credit Facility is at the discretion of the banks and is subject to change at any time.
The Credit Facility is secured by a lien on, and a security interest in, a majority of the Company's proved oil and gas properties and related assets (subject to prior security interests granted to holders of volumetric production payment agreements), a pledge of accounts receivable, material contracts and the stock of material subsidiaries, and a negative pledge on remaining assets. The maturity date of the Credit Facility is December 31, 1996. Under the terms of the Credit Facility, the Company is subject to certain covenants and financial tests (which may from time to time restrict the Company's activities), including restrictions or requirements with respect to working capital, net cash flow, additional debt, asset sales, mergers, cash dividends on capital stock and reporting responsibilities. At December 31, 1994 the outstanding balance under this facility was $33,000,000, and the Company was in compliance with the covenants of the Credit Facility. The Company currently anticipates that it may not meet the Credit Facility's working capital and/or interest coverage ratio tests during 1995. Management believes that any instances of noncompliance can be cured within the period of time permitted or that waivers can be obtained from the banks, although there can be no assurance that this will be the case.
At March 31, 1995, the outstanding balance under the Credit Facility was $45,000,000. The Company has used the facility for a $1,500,000 letter of credit, leaving an available borrowing capacity of $3,500,000, which the Company intends to use to meet monthly cash flow requirements.
On April 13, 1995 Forest sold to a bank a participation interest in Forest's claim in a bankruptcy proceeding as described in Item 3. Legal Proceedings. Consideration received consisted of a $4,000,000 nonrecourse loan, in exchange for which the bank will receive, solely from the proceeds of the bankruptcy claim, an amount equal to the loan principal plus accrued interest at 16.5% per annum plus 25% of the excess, if any, of the proceeds over the loan principal and interest. The Company may, under certain conditions, limit the overall cost of financing to 23.5% per annum by exercising its option to repurchase the bank's interest in the bankruptcy claim prior to receipt of any proceeds of the claim. Proceeds from this sale will be used for working capital needs.
Based on the Company's actions taken to date and its plans, including the recent developments described above, management believes the Company will have adequate sources of short-term liquidity to meet its working capital needs, fund capital expenditures at reduced levels, and meet its current debt service obligations.
CASH FLOW. Historically, one of the Company's primary sources of capital has been funds provided by operations, which has varied dramatically in prior periods depending upon factors such as natural gas contract settlements and price fluctuations which are difficult to predict.
The following summary table reflects comparative cash flows for the Company for the periods ended December 31, 1994, 1993 and 1992:
LONG-TERM LIQUIDITY. The Company has historically addressed its long-term liquidity needs through the use of nonrecourse production-based financing and through issuance of debt and common stock when market conditions permit. Significant events affecting the Company's long-term liquidity over the past few years are discussed below.
In December, 1992, the Company received gross proceeds of $51,250,000 as a result of the ONEOK settlement. The net proceeds, after payment of related royalties and production taxes, were approximately $36,429,000. Pursuant to the terms of its 12 3/4% Senior Secured Notes, the Company was required to make an offer to purchase $16,000,000 principal amount of the 12 3/4% Senior Secured Notes at a purchase price of 100% of their principal amount plus accrued interest to the date of purchase. Pursuant to such offer, the Company purchased approximately $3,926,000 principal amount of 12 3/4% Senior Secured Notes in February, 1993. The remainder of the net proceeds were used for general corporate purposes, including working capital, debt reduction and the acquisition of oil and gas properties.
On June 15, 1993, the Company issued 11,080,000 shares of Common Stock for $5.00 per share in a public offering. The net proceeds from the issuance of the shares totalled approximately $51,506,000 after issuance costs and underwriting fees, of which the Company used approximately $30,300,000 to purchase or redeem a portion of its 12 3/4% Senior Secured Notes. The remainder of the net proceeds was used for general corporate purposes, including working capital, debt reduction and the acquisition of oil and gas properties.
On September 8, 1993, the Company completed a public offering of $100,000,000 aggregate principal amount of 11-1/4% Senior Subordinated Notes due September 1, 2003. The 11 1/4% Senior Subordinated Notes were issued at a price of 99.259% yielding 11.375% to the holders. On October 13, 1993 the Company used the net proceeds from the sale of the 11 1/4% Senior Subordinated Notes of approximately $95,827,000, together with approximately $19,400,000 of available cash, to redeem all of its outstanding 12 3/4% Senior Secured Notes and long-term subordinated debentures.
On November 9, 1993, the Company purchased $308,000 principal amount of its 5 1/2% Convertible Subordinated Debentures. The remaining $7,171,000 principal amount of the 5 1/2% Debentures was redeemed February 1, 1994.
On December 30, 1993, the Company entered into a nonrecourse secured loan agreement (the Enron loan) arranged by Enron Finance Corp., an affiliate of Enron Gas Services. For a further discussion of the Enron loan, see "Nonrecourse Secured Loan and Dollar-Denominated Production Payment" below. This financing provided acquisition capital, and capital to execute Forest's exploitation strategy.
Many of the factors which may affect the Company's future operating performance and long-term liquidity are beyond the Company's control, including, but not limited to, oil and natural gas prices, governmental actions and taxes, the availability and attractiveness of properties for acquisition, the adequacy and attractiveness of financing and operational results. The Company continues to examine alternative sources of long-term liquidity, including public and private issuances of equity and refinancing debt with equity.
VOLUMETRIC PRODUCTION PAYMENTS. Through December 31, 1994, the Company received approximately $139,058,000 (net of fees) from the sale of volumetric production payments and, in return, committed to deliver from the subject properties approximately 80.1 BCF of natural gas and 770,000 barrels of oil to entities associated with Enron Corp. (Enron). As of December 31, 1994, the volumes remaining to be delivered were approximately 19.1 BCF of natural gas and 261,000 barrels of oil. Amounts received for volumetric production payments are recorded as deferred revenue, which is amortized as sales are recorded based upon the scheduled deliveries under the production payment agreements.
The Company is required to deliver the scheduled volumes from the subject properties or to make a cash payment for volumes produced but not delivered, in combination not to exceed a specified percentage of monthly production. If production levels are not sufficient to meet scheduled delivery commitments, the Company must account for and make up such shortages, at market-based prices, from future production.
The purchaser of a volumetric production payment determines the amount paid to the Company for the production payment by calculating the net present value of the scheduled deliveries priced using the purchaser's assumed future prices. However, the sales price per MCFE recorded by the Company upon delivery of production payment volumes is determined by dividing the net proceeds from the sale of the production payment by the total volumes scheduled to be delivered. This price is therefore fixed at the inception of the production payment and does not change. There is no interest expense recorded with respect to a volumetric production payment, the interest factor having been effectively netted against the calculated sales price. In addition, the Company must pay applicable royalties on volumes delivered and is responsible for production- related costs associated with operating the properties subject to the production payment agreements. These accounting treatments should be considered when assessing the Company's financial statements and related information, including information presented with respect to cash flows and average prices for volumes sold under fixed contracts.
Deferred revenue relating to production payments was $35,908,000 as of December 31, 1994. The annual amortization of deferred revenue and the corresponding delivery and net sales volumes are set forth below:
NONRECOURSE SECURED LOAN AND DOLLAR-DENOMINATED PRODUCTION PAYMENT. Under the terms of the Enron loan agreement and the dollar-denominated production payment, the Company is required to make payments based on the net proceeds, as defined, from certain subject properties. The terms of the Enron loan will be restructured based on the terms of a letter of intent as described in "Recent Developments."
The Enron loan, which bears annual interest at the rate of 12.5%, was recorded at a discounted amount to reflect the conveyance to the lender of a 20% interest in the net profits, as defined, of properties located in south Texas. At December 31, 1994 the principal amount of the loan was $61,717,000 and the recorded liability was $57,840,000. Under the terms of the Enron loan, additional funds may be advanced to fund a portion of the development projects which will be undertaken by the Company on the properties pledged as security for the loan. Payments of principal and interest under the Enron loan are due monthly and are equal to 90% of total net operating income from the secured properties, reduced by 80% of allowable capital expenditures, as defined. The Company's current estimate, based on expected production and prices, budgeted capital expenditure levels and expected discount amortization, is that 1995 payments will reduce the recorded liability by approximately $524,000. Estimated liability reductions, including required principal payments, for 1996 through 1999, under the same production, pricing, capital expenditure and discount scenario are approximately $11,280,000, $18,741,000, $15,119,000 and $9,113,000, respectively. Payments, if any, under the net profits conveyance will commence upon repayment of the principal amount of the Enron loan and will cease when the lender has received an internal rate of return, as defined, of 18% (15.25% through December 31, 1995). Properties to which approximately 22% of the Company's estimated proved reserves are attributable, on an MCFE equivalent basis, are dedicated to repayment of the Enron loan.
Under the provisions of the Enron loan, the Company is required to make periodic principal payments, beginning in February 1996, if the outstanding balance of the loan exceeds specified balances and the cash flow (as defined) from the mortgaged properties is less than specified minimums. Based upon current projections, the Company anticipates that these provisions will require a significant principal payment in February 1996 to avoid an event of default. As described above, the Company has signed a letter of intent to restructure the loan.
The original amount of the dollar-denominated production payment was $37,550,000, which was recorded as a liability of $28,805,000 after a discount to reflect a market rate of interest. At December 31, 1994 the remaining principal amount was $23,373,000 and the recorded liability was $18,534,000. Under the terms of this production payment, the Company must make a monthly cash payment which is the greater of a base amount or 85% of the net proceeds from the subject properties, as defined, except that the amount required to be paid in any given month shall not exceed 100% of the net proceeds from the subject properties. The Company retains a management fee equal to 10% of sales from the properties, which is deducted in the calculation of net proceeds. The Company's current estimate, based on expected production and prices, budgeted capital expenditure levels and expected discount amortization, is that 1995 payments will reduce the recorded liability by approximately $1,112,000. Estimated liability reductions for 1996 through 1999, under the same production, pricing, capital expenditure and discount scenario are approximately $811,000, $1,177,000, $2,988,000 and $4,220,000, respectively. Properties to which approximately 8% of the Company's estimated proved reserves are attributable, on an MCFE basis, are dedicated to this production payment financing through July 1999.
HEDGING PROGRAM. In addition to the volumes of natural gas and oil dedicated to volumetric production payments, the Company has also used energy swaps and other financial agreements to hedge against the effects of fluctuations in the sales prices for oil and natural gas. In a typical swap agreement, the Company receives the difference between a fixed price per unit of production and a price based on an agreed upon third-party index if the index price is lower. If the index price is higher, the Company pays the difference. The Company's current swaps are settled on a monthly basis. At December 31, 1994, the Company had natural gas swaps and collars for an aggregate of approximately 27.5 BBTU (billion British Thermal Units) per day of natural gas during 1995 at fixed prices (NYMEX basis) ranging from $1.90 to $2.38 per MMBTU (million British Thermal Units) and an aggregate of approximately 16.7 BBTU per day of natural gas during 1996 at fixed prices and floors ranging from $1.96 to $2.37 per MMBTU. At December 31, 1994 the Company had oil swaps for an aggregate of approximately 1,300 barrels per day of oil during 1995 at fixed prices ranging from $16.70 to $17.75 (NYMEX basis) and an aggregate of approximately 1,000 barrels per day of oil from January, 1996 through June, 1996 at fixed prices ranging from $16.70 to $17.75 per barrel.
OPTION AGREEMENT. In 1993, under another agreement (the Option Agreement), the Company paid a premium of $516,000 in conjunction with the closing of the Enron loan agreement. The payment of this premium gave Forest the right to set a floor price of $1.70 per MMBTU on a total of 18,400 BBTU of natural gas over a five year period commencing January 1, 1995. In order to exercise this right to set a floor, the Company must pay an additional premium of 10 CENTS per MMBTU, effectively setting the floor at $1.60 per MMBTU. The option agreement is broken into five calendar year periods with the option for each calendar year expiring four trading days prior to the last trading day for the January NYMEX contract for that year. The Company was able to sell its 1995 option, covering approximately 4,300 BBTU, for $25,000 a few days prior to expiration when the 1995 swap price was approximately $1.73 per MMBTU. The options for calendar years 1996 through 1999 remain in place.
SUMMARY OF CASH FLOW CONSIDERATIONS AND EXPOSURE TO PRICE AND RESERVE RISK. Pursuant to certain of the Company's financing arrangements, significant amounts of production are contractually dedicated to production payments and the repayment of nonrecourse debt over the next five years (dedicated volumes). The dedicated volumes decrease over the next five years and also decrease as a percentage of the Company's total production during this period. The production volumes not contractually dedicated to repayment of nonrecourse debt (undedicated volumes) are relatively stable but increase as a percentage of the Company's total production over the next five years. This relative stability of undedicated volumes is due to the fact that the decrease in dedicated volumes corresponds generally to the Company's estimates of the decrease in its total production. In the Company's opinion, the relative stability of undedicated volumes should provide a more constant level of cash flow available for corporate purposes other than debt repayment. The following table presents, on a percentage basis, the Company's estimates of dedicated and undedicated volumes as a percentage of estimated total production:
As a result of volumetric production payments, energy swaps and fixed contracts, the Company currently estimates that approximately 59% of its natural gas production and 51% of its oil production will not be subject to price fluctuations from January 1995 through December 1995. It is estimated that existing volumetric production payments, energy swaps, collars and fixed contracts currently cover approximately 41% (including the option to purchase the $1.70 floor described above) of the Company's natural gas production and 23% of its oil production for the year ending December 31, 1996. Currently, it is the Company's intention to commit no more than 75% of its anticipated total production and no more than 85% of its anticipated undedicated production to such arrangements at any point in time. See "Hedging Program" above.
The Company's hedging strategy for dedicated volumes differs from that for undedicated volumes. The Company believes that hedging of dedicated volumes provides for greater assurance of debt repayment and decreased financial risk. The Company believes that hedging undedicated volumes is also warranted in order to facilitate its short-term planning and budgeting. The Company has not hedged significant amounts of undedicated volumes beyond 36 months. The Company may consider long-term hedging of undedicated volumes in the future if product prices rise to significantly higher levels. The Company believes that stability of cash flow should be considered by separately reviewing its hedge position relative to dedicated volumes and undedicated volumes. The following table reflects the estimated hedge position as a percentage of the Company's undedicated volumes:
The Company believes it is important to hedge volumes dedicated to production payments or required to repay debt. The following table reflects the estimated hedge position as a percentage of the Company's dedicated volumes. (Volumes attributable to volumetric production payments are treated as hedged for purposes of this presentation):
Estimates of commercially recoverable oil and gas reserves and of the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the subject properties, comparison with other producing properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and gas prices and future operating costs, severance and excise taxes, abandonment costs, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. All such estimates are to some degree speculative. Actual production, revenues, severance and excise taxes, development expenditures, workover and remedial expenditures, abandonment expenditures and operating expenditures with respect to the Company's reserves will likely vary from such estimates, and such variances may be material.
CAPITAL EXPENDITURES. The Company's expenditures for property acquisition, exploration and development for the past three years, were as follows:
In 1994, the Company's property acquisition expenditures of $9,762,000 resulted in proved reserve additions of an estimated 8.2 BCF of natural gas and 17,000 barrels of oil, as measured at the closing dates of the acquisitions for financial accounting purposes. In 1993, the Company's property acquisition expenditures of $144,916,000 resulted in proved reserve additions of an estimated 94.7 BCF of natural gas and 1.7 million barrels of oil, as measured at the closing dates, as well as eight exploitation prospects and three exploratory offshore blocks. In 1992, the Company's property acquisition expenditures, as measured at the closing dates, of $88,772,000 resulted in proved reserve additions of an estimated 63 BCF of natural gas and 5.8 million barrels of oil, including reserves acquired as a result of gas balancing settlements.
The Company's 1995 budgeted expenditures for exploration and development are approximately $5,700,000, and $12,300,000, respectively, including capitalized overhead of $2,300,000 and $3,600,000, respectively.
During 1995, the Company intends to continue a strategy of acquiring reserves that meet its investment criteria; however, no assurance can be given that the Company can locate or finance any property acquisitions. In order to finance future acquisitions, the Company is exploring many options including, but not limited to: a variety of debt instruments; sale of production payments or other nonrecourse financing; the issuance of net profits interests; sales of non-strategic properties, prospects and technical information or joint venture financing. Availability of these sources of capital and, therefore, the Company's ability to execute its operating strategy will depend upon a number of factors, some of which are beyond the control of the Company. If adequate sources of liquidity are not available to the Company in 1995, the amount invested in exploration, development and reserve acquisitions may be reduced due principally to the desire of the Company to protect its capital in the event of inadequate liquidity.
OTHER MATTERS
GAS BALANCING. The Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994. Under the sales method previously used by the Company, all proceeds from production credited to the Company were recorded as revenue until such time as the Company had produced its share of related reserves. Under the entitlements method, revenue is recorded based upon the Company's share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes
produced. Under the entitlements method, the Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue.
As of December 31, 1994 the Company had produced approximately 8.4 BCF more than its entitled share of production. The undiscounted value of this imbalance is approximately $14,260,000, of which $5,735,000 is reflected on the balance sheet as a short-term liability and the remaining $8,525,000 is reflected on the balance sheet as a long-term liability.
UNFUNDED PENSION LIABILITIES. In 1994, in response to market conditions, the Company increased from 7.5% to 9% the discount rate used in determining the actuarial present value of the projected benefit obligations under its qualified defined benefit trusteed pension plan and its supplemental executive retirement plan. As a result of the change in the discount rate, the Company reduced the liability representing the unfunded liabilities of these plans by approximately $1,570,000 with a corresponding increase in capital surplus. The Company does not expect the change in discount rate to have a significant impact on future expense due to a pension plan curtailment effected May 31, 1991. The Company currently is not required to make a contribution to the pension plan under the minimum funding requirements of ERISA, but may choose to do so or may be required to do so in the future.
NATURAL GAS SALES CONTRACTS. The Company had two natural gas sales contracts with Columbia Gas Transmission Corp. (Transmission), a subsidiary of Columbia Gas System (CGS). On July 31, 1991, CGS and Transmission filed Chapter 11 bankruptcy petitions with the United States Bankruptcy Court for the District of Delaware. Both contracts have been rejected pursuant to the bankruptcy proceedings. The Company has filed a proof of claim in the bankruptcy proceeding consisting of a secured claim of $1,600,000 based on Louisiana vendor lien laws and an unsecured claim relating to the rejection of the contracts. The secured claim arises from Transmission's failure to pay the contract price for a period of time prior to rejection of the contracts. The unsecured claim was calculated on an undiscounted basis and without any assumption of mitigation of damages through spot market sales. No prediction can be given as to when or how these matters will ultimately be concluded. The Company sold a participation interest in the claim to a bank on April 13, 1995, as discussed above under "Liquidity and Capital Resources".
NET OPERATING LOSS AND TAX CREDIT CARRYFORWARDS. At December 31, 1994, the Company estimated that for United States federal income tax purposes, it had consolidated net operating loss carryforwards of $57,044,000, depletion carryforwards of approximately $19,879,000 and investment tax credit carryforwards of approximately $3,674,000. The availability of some of these tax attributes to reduce current and future taxable income of the Company is subject to various limitations under the Internal Revenue Code of 1986, as amended (the Code). In particular, the Company's ability to utilize such tax attributes could be severely restricted due to the occurrence of an "ownership change" within the meaning of Section 382 of the Code resulting from the 1991 recapitalization. At December 31, 1994, the Company estimated that net operating loss and investment tax credit carryforwards would be limited to offset current taxable income to the extent described below.
Approximately $46,000,000 of the net operating loss carryforwards are not subject to the provisions of Section 382 as they were generated subsequent to the ownership change. Even though the Company is limited in its ability to use the remaining net operating loss carryforwards under the general provisions of Section 382, it may be entitled to use these net operating loss carryovers to offset (a) gains recognized in the five years following the ownership change on the disposition of certain assets, to the extent that the value of the assets disposed of exceeds its tax basis on the date of the ownership change or (b) any item of income which is properly taken into account in the five years following the ownership change but which is attributable to periods before the ownership change ("built-in gain"). The ability of the Company to use these net operating loss carryovers to offset built-in gain first requires that the Company have total built-in gains at the time of the ownership change which are greater than a threshold amount. In addition, the use of these net operating loss carryforwards to offset built-in gain cannot exceed the amount of the total built-in gain.
The Company believes that due to the amount of built-in gain as of the date of ownership change, and the recognition of such gain through December 31, 1994, that there will be no significant limitation on the Company's ability to use these net operating loss carryforwards or investment tax credit carryforwards.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information concerning this Item begins on the following page.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders Forest Oil Corporation:
We have audited the accompanying consolidated balance sheets of Forest Oil Corporation and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the years in the three-year period ended December 31, 1994. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Forest Oil Corporation and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1994 in conformity with generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994.
As discussed in Notes 6 and 10 of Notes to Consolidated Financial Statements, the Company adopted the provisions of Financial Accounting Standards Board Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" and Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" in 1993.
KPMG PEAT MARWICK LLP
Denver, Colorado March 30, 1995, except as to Note 17 which is as of April 17, 1995
FOREST OIL CORPORATION CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS
(continued on following page)
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (CONTINUED)
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1994, 1993 AND 1992
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: - - - --------------------------------------------------------------------------------
BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Forest Oil Corporation (the Company) and its wholly-owned subsidiaries. Significant intercompany balances and transactions are eliminated.
CASH EQUIVALENTS - For purposes of the statements of cash flows, the Company considers all debt instruments with original maturities of three months or less to be cash equivalents.
PROPERTY AND EQUIPMENT - The Company uses the full cost method of accounting for oil and gas properties. Presently, the Company's operations are conducted in the United States. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. Capitalized costs are depleted using the units of production method. A reserve is provided for estimated future costs of site restoration, dismantlement and abandonment activities as a component of depletion. Unusually significant investments in unproved properties, including related capitalized interest costs, are not depleted pending the determination of the existence of proved reserves. As of December 31, 1994, 1993 and 1992, there were undeveloped property costs of $30,441,000, $41,216,000 and $18,306,000, respectively, in the United States which were not being depleted.
Depletion per unit of production was determined based on conversion to common units of measure using one barrel of oil as an equivalent to six MCF of natural gas. Depletion per unit of production (MCFE) for each of the Company's cost centers was as follows:
Capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves; 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. As a result of this limitation on capitalized costs, the accompanying financial statements include a provision for impairment of oil and gas property costs of $58,000,000 in 1994. There was no impairment of oil and gas property costs in 1993 or 1992.
Gain or loss is recognized only on the sale of oil and gas properties involving significant reserves.
Buildings, transportation and other equipment are depreciated on the straight- line method based upon estimated useful lives of the assets ranging from five to forty-five years.
OIL AND GAS SALES - The Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994. Under the sales method previously used by the Company, all proceeds from production credited to the Company were recorded as revenue until such time as the Company had produced its share of related reserves. Under the entitlements method, revenue is recorded based upon the Company's share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced.
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONT'D): - - - --------------------------------------------------------------------------------
Under the entitlements method, the Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue. The Company believes that the entitlements method is preferable because it allows for recognition of revenue based on the Company's actual share of jointly owned production and provides a better matching of revenue and related expenses.
The cumulative effect of the change for the periods through December 31, 1993 was a charge of $13,990,000. The effect of this change on 1994 was an increase in earnings from operations of $3,584,000 and an increase in production volumes of 1,555,000 MCF. There were no related income tax effects in 1994. As the Company adopted this change in the fourth quarter of 1994, previously reported 1994 quarterly information has been restated to reflect the change effective January 1, 1994. See Note 15 for restated selected quarterly financial data. The pro forma amounts shown on the consolidated statements of operations have been adjusted for the effect of the retroactive application of the change and related income taxes.
As of December 31, 1994 the Company had produced approximately 8.4 BCF more than its entitled share of production. The estimated value of this imbalance is approximately $14,260,000, which is reflected on the accompanying balance sheet as a short-term liability of $5,735,000 and a long-term liability of $8,525,000.
HEDGING TRANSACTIONS - In order to minimize exposure to fluctuations in oil and natural gas prices, the Company hedges the price of future oil and natural gas production by entering into certain contracts and financial arrangements. Gains and losses related to these hedging transactions are recognized as adjustments to revenue recorded for the related production. Costs associated with the purchase of certain hedge instruments are deferred and amortized against revenue related to hedged production.
INCOME TAXES - The adoption of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109), effective January 1, 1993 changed the Company's method of accounting for income taxes from the deferred method to an asset and liability method. Previously, the Company deferred the tax effects of timing differences between financial reporting and taxable income. The asset and liability method requires the recognition of 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.
FOREIGN CURRENCY TRANSLATION - Assets and liabilities related to Canadian investments are generally translated at current exchange rates, and related translation adjustments are reported as a component of shareholders' equity. Income statement accounts are translated at the average rates during the period.
EARNINGS (LOSS) PER SHARE - Primary earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares and common share equivalents outstanding during each period, excluding treasury shares. Net earnings (loss) attributable to common stock represents net earnings (loss) less preferred stock dividend requirements of $2,161,000 in 1994, $2,250,000 in 1993 and $2,348,000 in 1992. Common share equivalents include, when applicable, dilutive stock options using the treasury stock method and warrants using the if converted method.
Fully diluted earnings per share is computed assuming, in addition to the above, (i) that convertible debentures were converted at the beginning of each period or date of issuance, if later, with earnings being increased for interest expense, net of taxes, that would not have been incurred had conversion taken place, (ii) that convertible preferred stock was converted at the beginning of each period or date of issuance, if later, and (iii) any additional dilutive effect of stock options and warrants. The effects of these assumptions were anti-dilutive in 1994 and 1993. The weighted average number of shares outstanding on a fully-diluted basis was 26,515,000 for the year ended December 31, 1992.
RECLASSIFICATIONS - Certain amounts in the 1993 and 1992 financial statements have been reclassified to conform to the 1994 financial statement presentation.
(2) ACQUISITIONS: - - - --------------------------------------------------------------------------------
During 1994, the Company completed acquisitions totaling $9,762,000, including additional interests in properties acquired in 1993. In order to finance one of the acquisitions, the Company sold a volumetric production payment for approximately $4,353,000 (net of fees).
In May and December, 1993, the Company purchased interests in properties from Atlantic Richfield Company (ARCO) for approximately $60,862,000. In conjunction with the ARCO acquisitions, the Company sold volumetric production payments from certain of the ARCO properties for approximately $40,468,000 (net of fees). In December 1993, the Company purchased interests in offshore properties for approximately $24,050,000 and interests in properties in south Texas for approximately $59,458,000. In conjunction with these acquisitions, the Company entered into a nonrecourse secured loan agreement for $51,600,000.
In February 1992, Forest I Development Company, a wholly-owned subsidiary of the Company, purchased substantially all of the assets of Harbert Energy Corporation and its associated entities in an acquisition accounted for as a purchase. The purchase price of $40,400,000 was funded primarily through the sale of a dollar- denominated production payment which was recorded at its present value of $28,805,000. In July 1992, the Company purchased Transco Exploration and Production Company (TEPCO) for approximately $45,000,000. In conjunction with the acquisition, the Company sold a volumetric production payment from certain of the TEPCO properties for approximately $38,500,000 (net of fees).
The Company's results of operations for the year ended December 31, 1993 include the effects of the first ARCO acquisition since May 1, 1993 and the offshore properties and the second ARCO acquisition since December 1, 1993. The Company's results of operations for the year ended December 31, 1992 include the effects of the Harbert and TEPCO acquisitions since February 1, 1992 and August 1, 1992, respectively.
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE: - - - --------------------------------------------------------------------------------
In May 1992, the Company transferred substantially all of its Canadian oil and gas properties to a wholly-owned Canadian subsidiary, Forest Canada I Development Ltd. (FCID). In September 1992, FCID sold its Canadian assets and related operations to CanEagle Resources Corporation (CanEagle) for approximately $51,250,000 in Canadian funds ($41,000,000 U.S.). CanEagle was formed for the purpose of acquiring the assets and related operations of FCID. In the transaction, FCID received cash of approximately $28,000,000 CDN ($22,400,000 U.S.), net of expenses, and provided financing in the aggregate principal amount of $22,000,000 CDN ($17,600,000 U.S.). On June 24, 1994, CanEagle sold a significant portion of its oil and gas properties in Canada to a third party. In conjunction with this transaction, the Company received payment of $6,124,000 CDN ($4,400,000 U.S.) representing principal and unpaid interest on a CanEagle subordinated debenture held by the Company. In addition, the Company exchanged its remaining investment in CanEagle for preferred shares of a newly formed entity, Archean Energy, Ltd. (Archean).
The Company has accounted for the proceeds from the aforementioned transactions as reductions in the carrying value of its investment in and advances to its Canadian affiliates. The Company accounts for its investment in Canadian affiliates in a manner analagous to equity accounting. Losses will be recognized to the extent that the Canadian affiliates' losses are attributable to the Company's interest. Earnings will be recognized only if realization is assured. No earnings or losses attributable to the investment in Canadian affiliates have been recognized in 1994, 1993 or 1992.
(4) LONG-TERM DEBT: - - - --------------------------------------------------------------------------------
Long-term debt at December 31, 1994 and 1993 consists of the following:
BANK DEBT: The Company has a secured credit facility (The Credit Facility) with The Chase Manhattan Bank, NA. (Chase) as agent for a group of banks. Under the Credit Facility, the Company may borrow up to $17,500,000 for acquisition or development of proved oil and gas reserves, and up to $32,500,000 for working capital and general corporate purposes, subject to semi-annual redemption at the banks' discretion. The total borrowing capacity of the Company under the Credit Facility is $50,000,000. In March, 1995, the banks completed their most recent semi-annual redetermination of the Credit Facility and advised the Company that the maximum borrowing capacity would be maintained at $50,000,000. However, the amount of the maximum borrowings under the Credit Facility is at the discretion of the banks and is subject to change at any time.
The Credit Facility is secured by a lien on, and a security interest in, a majority of the Company's proved oil and gas properties and related assets (subject to prior security interests granted to holders of volumetric production payment agreements), a pledge of accounts receivable, material contracts and the stock of material subsidiaries, and a negative pledge on remaining assets. The maturity date of the Credit Facility is December 31, 1996. Under the terms of the Credit Facility, the Company is subject to certain covenants and financial tests (which may from time to time restrict the Company's activities), including restrictions or requirements with respect to working capital, net cash flow, additional debt, asset sales, mergers, cash dividends on capital stock and reporting responsibilities. At December 31, 1994 the outstanding balance under the Credit Facility was $33,000,000 at interest rates ranging from 7.255% to 8.875% and the Company was in compliance with the covenants of the Credit Facility. The Company currently anticipates that it may not meet the working capital and/or interest coverage ratio tests during 1995. Management believes, however, that any instances of noncompliance can be cured within the period of time permitted or that waivers can be obtained from the banks.
NONRECOURSE SECURED LOAN: On December 30, 1993, the Company entered into a nonrecourse secured loan agreement arranged by Enron Finance Corp., an affiliate of Enron Gas Services (the Enron loan). Advances under the loan agreement bear annual interest at the rate of 12.5%. Approximately $51,600,000 was advanced on December 30, 1993 to provide financing for acquisitions. Another $5,800,000 of the available balance was advanced on December 30, 1993 to fund a portion of the development projects which will be undertaken by the Company on the properties pledged as security for the loan. Under the terms of the Enron loan, additional funds may be advanced to fund additional development projects which will be undertaken by the Company on the properties pledged as security for the loan.
The loan was recorded at a discount to reflect conveyance to the lender of a 20% interest in the net profits, as defined, of properties located in south Texas. This discount of $4,299,000 is being amortized over the life of the loan using the effective interest method. At December 31, 1994 the principal amount of the loan was $61,717,000 and the recorded liability was $57,840,000.
Payments of principal and interest under the Enron loan are due monthly and are equal to 90% of total net operating income from the secured properties, reduced by 80% of allowable capital expenditures, as defined. The
(4) LONG-TERM DEBT (CONT'D): - - - --------------------------------------------------------------------------------
Company's current estimate, based on expected production and prices, budgeted capital expenediture levels and expected discount amortization, is that 1995 payments will reduce the recorded liability by approximately $524,000. This amount is included in current liabilities. Estimated liability reductions, including required principal payments, for 1996 through 1999, under the same production, pricing, capital expenditure and discount scenario, are approximately $11,280,000, $18,741,000, $15,119,000 and $9,113,000, respectively. Payments, if any, under the net profits conveyance will commence upon repayment of the principal amount of the Enron loan and will cease when the lender has received an internal rate of return, as defined, of 18% (15.25% through December 31, 1995). The Company has signed a letter of intent to restructure the loan as described in Note 17.
PRODUCTION PAYMENT OBLIGATION: The original principal amount of the dollar-denominated production payment was $37,550,000, which was recorded as a liability of $28,805,000 after a discount to reflect a market rate of interest of 15.5%. At December 31, 1994 the remaining principal amount was $23,373,000 and the recorded liability was $18,534,000. Under the terms of this production payment, the Company must make a monthly cash payment which is the greater of a base amount or 85% of net proceeds from the subject properties, as defined, except that the amount required to be paid in any given month shall not exceed 100% of the net proceeds from the subject properties. The Company retains a management fee equal to 10% of sales from the properties, which is deducted in the calculation of net proceeds. The Company's current estimate, based on expected production and prices, budgeted capital expenditure levels and expected discount amortization, is that 1995 payments will reduce the recorded liability by approximately $1,112,000; this amount is included in current liabilities. Estimated liability reductions for 1996 through 1999, under the same production, pricing, capital expenditure and discount scenario, are $811,000, $1,177,000, $2,988,000 and $4,220,000, respectively.
11-1/4% SUBORDINATED DEBENTURES: On September 8, 1993 the Company completed a public offering of $100,000,000 aggregate principal amount of 11-1/4% Senior Subordinated Notes due September 1, 2003. The Senior Subordinated Notes were issued at a price of 99.259% yielding 11.375% to the holders. The Company used the net proceeds from the sale of the Senior Subordinated Notes of approximately $95,827,000, together with approximately $19,400,000 of available cash, to redeem all of its outstanding Senior Secured Notes and long-term subordinated debentures. The redemptions resulted in a net loss of $15,387,000 which was recorded as an extraordinary loss of $10,735,000 (net of income tax benefit of $4,652,000).
The Senior Subordinated Notes are redeemable at the option of the Company, in whole or in part, at any time on or after September 1, 1998 initially at a redemption price of 105.688%, plus accrued interest to the date of redemption, declining at the rate of 1.896% per year to September 9, 2000 and at 100% thereafter. In addition, the Company may, at its option, redeem prior to September 1, 1996 up to 30% of the initially outstanding principal amount of the Notes at 110% of the principal amount thereof, plus accrued interest to the date of redemption, with the net proceeds of any future public offering of its Common Stock.
Under the terms of the Senior Subordinated Notes, the Company must meet certain tests before it is able to pay cash dividends (other than dividends on the Company's $.75 Convertible Preferred Stock) or make other restricted payments, incur additional indebtedness, engage in transactions with its affiliates, incur liens and engage in certain sale and leaseback arrangements. The terms of the Senior Secured Notes also limit the Company's ability to undertake a consolidation, merger or transfer of all or substantially all of its assets. In addition, the Company is, subject to certain conditions, obligated to offer to repurchase Senior Subordinated Notes at par value plus accrued and unpaid interest to the date of repurchase, with the net cash proceeds of certain sales or dispositions of assets. Upon a change of control, as defined, the Company will be required to make an offer to purchase the Senior Subordinated Notes at 101% of the principal amount thereof, plus accrued interest to the date of purchase.
5-1/2% SUBORDINATED DEBENTURES: At December 31, 1993 the 5-1/2% Convertible Subordinated Debentures had a remaining balance of $7,171,000 which was paid in full on the February 1, 1994 due date.
(5) DEFERRED REVENUE: - - - --------------------------------------------------------------------------------
From April 1991 through May 1993, the Company entered into four volumetric production payments with entities associated with Enron Corp. (Enron) for net proceeds of $121,498,000. Under the terms of these production payments, the Company was required to deliver 70.1 BCF of natural gas and 770,000 barrels of oil over periods ranging from three to six years.
Effective November 1, 1993, the four separate volumetric payment financings described above between the Company and Enron were consolidated into one production payment. The delivery schedules from the previously separate production payments were not adjusted; however, delivery shortfalls on any property can now be made up from excess production from any other property which is dedicated to the production payment obligation. The consolidation also provided that certain acreage previously committed to the production payments was released and can be developed by the Company unburdened by the delivery obligations of the production payment.
In connection with the purchase of interests in properties from ARCO in December 1993, a volumetric production payment from certain of the ARCO properties was sold to Enron for net proceeds of $13,207,000. This production payment covered approximately 7.3 BCF of natural gas to be delivered over 8 years.
In July 1994, the Company purchased additional interests in the properties acquired from ARCO in December 1993. In connection with this transaction, a volumetric production payment was sold to Enron for net proceeds of $4,353,000. This production payment covered approximately 2.7 BCF of natural gas to be delivered over 8 years.
The Company is required to deliver the scheduled volumes from the subject properties or to make a cash payment for volumes produced but not delivered, in combination not to exceed a specified percentage of monthly production. If production levels are not sufficient to meet scheduled delivery commitments, the Company must account for and make up such shortages, at market-based prices, from future production.
The Company is responsible for royalties and for production costs associated with operating the properties subject to the production payment agreements. The Company may grant liens on properties subject to the production payment agreements, but it must notify prospective lienholders that their rights are subject to the prior rights of the production payment owner.
Amounts received were recorded as deferred revenue. Volumes associated with amortization of deferred revenue for the years ended December 31, 1994, 1993 and 1992 were as follows:
(5) DEFERRED REVENUE (CONT'D): - - - --------------------------------------------------------------------------------
Future amortization of deferred revenue, based on the scheduled deliveries under the production payment agreements, is as follows:
(6) INCOME TAXES: - - - --------------------------------------------------------------------------------
The Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," (SFAS No. 109) on a prospective basis effective January 1, 1993. The cumulative effect of this change in accounting for income taxes of $2,060,000 was determined as of January 1, 1993 and was reported separately in the Consolidated Statement of Operations for the year ended December 31, 1993.
The income tax expense (benefit) is different from amounts computed by applying the statutory Federal income tax rate for the following reasons:
The Omnibus Budget Reconciliation Act of 1993 increased the Federal corporate tax rate from 34% to 35% retroactively to January 1, 1993. As a result of this tax increase, the tax benefits at December 31, 1994 and December 31, 1993, respectively, on the losses from continuing operations were approximately $677,000 and $167,000 less than such amounts would have been without such increase in the tax rate. However, due to limitations on the recognition of deferred tax assets, the total tax benefit at December 31, 1994 and December 31, 1993, including the tax benefit on the cumulative effect of the change in accounting method in 1994 and on the extraordinary loss on extinguishment of debt in 1993, is unaffected by the tax rate increase. The impact of the tax rate increase will be recognized when future taxable income allows the unrecognized deferred tax asset to be realized.
Deferred income taxes generally result from recognizing income and expenses at different times for financial and tax reporting. These differences result from recording proceeds from the sale of properties in the full cost pool, capitalization of certain development, exploration and other costs under the full cost method of accounting and the provision for impairment of oil and gas properties for financial accounting purposes.
(6) INCOME TAXES (CONT'D): - - - -------------------------------------------------------------------------------- The components of the net deferred tax liability, computed in accordance with SFAS No. 109 are as follows:
The valuation allowance for deferred tax assets as of January 1, 1994 was $8,142,000. The net change in the total valuation allowance for the tax year ended December 31, 1994 was an increase of $28,116,000. The total increase in the valuation allowance includes $4,896,000 resulting from the cumulative effect of the change in accounting for oil and gas sales from the sales method to the entitlements method.
The Alternative Minimum Tax (AMT) credit carryforward available to reduce future Federal regular taxes aggregated $2,206,000 at December 31, 1994. This amount may be carried forward indefinitely. Regular and AMT net operating loss carryforwards at December 31, 1994 were $57,044,000 and $55,387,000, respectively, and will expire in the years indicated below:
AMT net operating loss carryforwards can be used to offset 90% of AMT income in future years.
Investment tax credit carryforwards available to reduce future Federal income taxes aggregated $3,674,000 at December 31, 1994 and expire at various dates through the year 2001. Percentage depletion carryforwards available to reduce future Federal taxable income aggregated $19,879,000 at December 31, 1994. This amount may be carried forward indefinitely. The net operating loss and investment tax credit carryforwards have been recognized as a deferred tax asset, subject to a valuation allowance.
(6) INCOME TAXES (CONT'D): - - - --------------------------------------------------------------------------------
The availability of some of these tax attributes to reduce current and future taxable income of the Company is subject to various limitations under the Internal Revenue Code. In particular, the Company's ability to utilize such tax attributes could be severely restricted due to the occurrence of an "ownership change" within the meaning of Section 382 of the Internal Revenue Code resulting from the Company's 1991 recapitalization. At December 31, 1994, the Company estimated that net operating loss and investment tax credit carryforwards would be limited to offset current taxable income to the extent described below.
The net operating loss carryforwards which expire in 2008 and 2009 are not subject to the provisions of Section 382 as they were generated subsequent to the ownership change. Even though the Company is limited in its ability to use the remaining net operating loss carryovers under the general provisions of Section 382, it may be entitled to use these net operating loss carryovers to offset (a) gains recognized in the five years following the ownership change on the disposition of certain assets, to the extent that the value of the assets disposed of exceeds its tax basis on the date of the ownership change or (b) any item of income which is properly taken into account in the five years following the ownership change but which is attributable to periods before the ownership change ("built-in gain"). The ability of the Company to use these net operating loss carryovers to offset built-in gain first requires that the Company have total built-in gains at the time of the ownership change which are greater than a threshold amount. In addition, the use of these net operating loss carryforwards to offset built-in gain cannot exceed the amount of the total built-in gain.
The Company believes that due to the amount of built-in gain as of the date of ownership change, and the recognition of such gain through December 31, 1994, there is no significant limitation on the Company's ability to use these net operating loss carryforwards or investment tax credit carryforwards.
(7) PREFERRED STOCK: - - - --------------------------------------------------------------------------------
The Company has 10,000,000 shares of $.75 Convertible Preferred Stock authorized, par value $.01 per share, of which there were 2,880,973 shares outstanding at December 31, 1994 and 1993, with an aggregate liquidation preference of $28,809,730 at December 31, 1994 and 1993. This stock is convertible at any time, at the option of the holder, at the rate of 3.5 shares of Common Stock for each share of $.75 Convertible Preferred Stock, subject to adjustment upon occurrence of certain events. During 1994, no shares of $.75 Convertible Preferred Stock were converted into shares of Common Stock. The $.75 Convertible Preferred Stock is redeemable, in whole or in part, at the option of the Company, at any time after the earlier of (i) July 1, 1996 or (ii) the date on which the last reported sales price of the Common Stock will have been $7.50 or higher for at least 20 of the prior 30 trading days, at a redemption price of $10.33 per share during the twelve-month period which began July 1, 1994 and declining ratably to $10.00 per share at July 1, 1996 and thereafter, including accumulated and unpaid dividends. Cumulative annual dividends of $.75 per share are payable quarterly, in arrears, on the first day of February, May, August and November, when and as declared. Until December 31, 1993, the Company paid such dividends in shares of Common Stock. After such date, dividends may be paid in cash or, at the Company's election, in shares of Common Stock or in a combination of cash and Common Stock. However, the Company is prohibited from paying cash dividends on its $.75 Convertible Preferred Stock after the February 1, 1995 dividend due to restrictions contained in the Credit Agreement with its lending banks. Common Stock delivered in payment of dividend will be valued for dividend payment purposes at between 75% and 90%, based on trading volume, of the average last reported sales price of the Common Stock during a specified period prior to the record date for the dividend payment.
During any period in which dividends on preferred stock are in arrears, no dividends or distributions, except for dividends paid in shares of Common Stock, may be paid or declared on the Common Stock, nor may any shares of Common Stock be acquired by the Company.
(8) COMMON STOCK: - - - --------------------------------------------------------------------------------
The Company has 112,000,000 shares of Common Stock authorized, par value $.10 per share, of which there were 28,295,209 and 28,250,445 shares issued at December 31, 1994 and 1993, respectively, with 105,940 and 335,813 shares held by the Company at December 31, 1994 and 1993, respectively. The Common Stock is entitled to one vote per share. Prior to May 1993 the Company also had Class B stock which had superior voting rights to the Company's Common Stock, had limited transferability and was not traded in any public market but was convertible at any time into shares of Common Stock on a share-for-share basis. At the Company's Annual Meeting of Shareholders on May 12, 1993, the shareholders adopted amendments to the Company's Restated Certificate of Incorporation to increase the number of authorized shares of Common Stock to 112,000,000 and to reclassify each share of Class B Stock into 1.1 shares of Common Stock.
On June 15, 1993, the Company issued 11,080,000 shares of Common Stock for $5.00 per share in a public offering. The net proceeds from the issuance of the shares totalled approximately $51,506,000 after deducting issuance costs and underwriting fees.
On October 29, 1993 the Company paid a dividend distribution of one Preferred Share Purchase Right on each outstanding share of the Company's Common Stock. The Rights are exercisable only if a person or group acquires 20% or more of the Company's Common Stock or announces a tender offer which would result in ownership by a person or group of 20% or more of the Common Stock. Each Right initially entitles each shareholder to buy 1/100th of a share of a new series of Preferred Stock at an exercise price of $30.00, subject to adjustment upon certain occurrences. Each 1/100th of a share of such new Preferred Stock that can be purchased upon exercise of a Right has economic terms designed to approximate the value of one share of Common Stock. The Rights will expire on October 29, 2003, unless extended or terminated earlier.
The Company has Warrants outstanding which permit holders thereof to purchase 1,244,715 shares of Common Stock at an exercise price of $3.00 per share. The Warrants are noncallable by the Company and expire on October 1, 1996. The exercise price is payable in cash.
In March 1992, the Company adopted the 1992 Stock Option Plan under which non- qualified stock options may be granted to key employees and non-employee directors. The aggregate number of shares of Common Stock which the Company may issue under options granted pursuant to this plan may not exceed 10% of the total number of shares outstanding or issuable at the date of grant pursuant to outstanding rights, warrants, convertible or exchangeable securities or other options. The exercise price of an option may not be less than 85% of the fair market value of one share of the Company's Common Stock on the date of grant. The options vest 20% on the date of grant and an additional 20% on each grant anniversary date thereafter. The Company may, in its discretion, grant each optionee a cash bonus upon the exercise of each granted option.
A summary of stock option activity related to the Plan is as follows:
(9) GAS PURCHASE CONTRACT SETTLEMENT: - - - --------------------------------------------------------------------------------
On December 17, 1992, the Company and ONEOK, Inc. (ONEOK) agreed to settle the case styled Forest Oil Corporation v. ONEOK, Inc. (Number 71,582) and its companion case styled Forest Oil Corporation v. ONEOK, Inc. (Case No. C-89-53). The cases involved take-or-pay damages relating to a natural gas purchase contract between the Company and ONEOK. The settlement encompassed all disputed contracts, claims and future claims. The cash proceeds of $51,250,000 were received by the Company on December 24, 1992. Proceeds after deducting related royalties and production taxes were approximately $36,429,000. The ONEOK settlement increased the Company's net earnings for 1992 by approximately $24,043,000 or $1.75 per share.
(10) EMPLOYEE BENEFITS: - - - --------------------------------------------------------------------------------
PENSION PLANS:
The Company has a qualified defined benefit pension plan (Pension Plan). The Company has effected a curtailment of the Pension Plan pursuant to which all benefit accruals were suspended effective May 31, 1991.
The benefits under the Pension Plan are based on years of service and the employee's average compensation during the highest consecutive sixty-month period in the fifteen years prior to retirement. No contribution was made in 1994, 1993 or 1992. The following table sets forth the Pension Plan's funded status and amounts recognized in the Company's consolidated financial statements at December 31:
For 1994 the discount rate used in determining the actuarial present value of the projected benefit obligation was 9% and the expected long-term rate of return on assets was 9%. For 1993, the discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5% and the expected long-term rate of return on assets was 9%. For 1992, the discount rate used in determining the actuarial present value of the projected benefit obligation was 9% and the expected long-term rate of return on assets was 9%.
The components of net pension expense (benefit) for the years ended December 31, 1994, 1993 and 1992 are as follows:
(10) EMPLOYEE BENEFITS (CONT'D): - - - --------------------------------------------------------------------------------
The Company has a non-qualified unfunded supplementary retirement plan that provides certain officers with defined retirement benefits in excess of qualified plan limits imposed by Federal tax law. Benefit accruals under this plan were suspended effective May 31, 1991 in connection with suspension of benefit accruals under the Company's Pension Plan. At December 31, 1994 the projected benefit obligation under this plan totaled $480,000, which is included in other liabilities in the accompanying balance sheet. The projected benefit obligation is determined using the same discount rate as is used for calculations for the Pension Plan.
In 1993 as a result of the change in the discount rate for the Pension Plan and the supplementary retirement plan, the Company recorded a liability of $3,038,000 representing the unfunded pension liability and a corresponding decrease in capital surplus. As a result of the increase in the discount rate for the Pension Plan and the supplementary retirement plan in 1994, the Company reduced the liability representing the unfunded pension liability by approximately $1,570,000 with a corresponding increase in capital surplus.
RETIREMENT SAVINGS PLAN: The Company sponsors a qualified tax deferred savings plan in accordance with the provisions of Section 401(k) of the Internal Revenue Code. Employees may defer up to 10% of their compensation, subject to certain limitations. The Company matches the employee contributions up to 5% of employee compensation. In 1994, 1993 and 1992, Company contributions were made using treasury stock. The expense associated with the Company's contribution was $516,000 in 1994, $367,000 in 1993 and $454,000 in 1992.
Effective January 1, 1992 the plan was amended to include profit-sharing contributions by the Company. In 1994, the Company did not make any profit sharing contributions. The Company's profit-sharing contributions were made using Company stock valued at $276,000 and $465,000 for 1993 and 1992, respectively.
ANNUAL INCENTIVE PLAN: The Forest Oil Corporation Annual Incentive Plan (the Incentive Plan), which became effective January 1, 1992, permits participating employees to earn annual bonus awards payable in cash or in shares of the Company's Common Stock, generally based in part upon the Company attaining certain levels of performance. In 1994, no bonuses were awarded. In 1993 and 1992, the Company accrued bonuses of $426,000 and $930,000, respectively, under the Incentive Plan. Amounts awarded will be disbursed in equal annual installments over the succeeding three-year period.
EXECUTIVE RETIREMENT AGREEMENTS: The Company entered into Agreements in December 1990 (the Agreements) with certain executives and directors (the Retirees) whereby each executive retired from the employ of the Company as of December 28, 1990. Pursuant to the terms of the Agreements, the Retirees are entitled to receive supplemental retirement payments from the Company in addition to the amounts to which they are entitled under the Company's retirement plan. In addition, the Retirees and their spouses are entitled to lifetime coverage under the Company's group medical and dental plans, tax and other financial services, and payments by the Company in connection with certain club membership dues. The Retirees will also continue to participate in the Company's royalty bonus program until December 31, 1995. The Company has also agreed to maintain certain life insurance policies in effect at December 1990, for the benefit of each of the Retirees.
Six of the Retirees have subsequently resigned as directors. One of the Retirees continues to serve as a director and will be paid the customary non- employee director's fee. Pursuant to the terms of the retirement agreements, the former directors and any other Retiree who ceases to be a director (or his spouse) will be paid $2,500 a month until December 2000.
The Company's obligation to one retiree under a revised retirement agreement is payable in Common Stock or cash, at the Company's option, in May of each year from 1993 through 1996 at approximately $190,000 per year with the balance of $149,000 payable in May 1997. The retirement agreements for the other six Retirees, one of
(10) EMPLOYEE BENEFITS (CONT'D): - - - --------------------------------------------------------------------------------
whom received in 1991 the payments scheduled to be made in 1999 and 2000, provide for supplemental retirement payments totalling approximately $938,400 per year through 1998 and approximately $740,400 per year in 1999 and 2000.
The present value of the amounts due under the agreements, discounted at 13%, has been recorded as retirement benefits payable to executives and directors.
LIFE INSURANCE: The Company provides life insurance benefits for certain key employees and retirees under split dollar life insurance plans. The premiums paid for the life insurance policies were $916,000, $861,000, and $995,000 in 1994, 1993 and 1992, respectively, including $831,000, $766,000 and $765,000 paid for policies for retired executives. Under the life insurance plans, the Company is assigned a portion of the benefits which is designed to recover the premiums paid.
HEALTH AND DENTAL INSURANCE: The Company provides health and dental insurance to all of its employees, eligible retirees and eligible dependents. The Company provides these benefits at nominal cost to employees and retirees who are required to contribute an estimated 50% of the cost of dependent coverage. In 1994, 1993 and 1992 the costs of providing these benefits for both active and retired employees totalled $1,714,000, $1,350,000 and $1,359,000, respectively. The 1994 cost includes $1,384,000 related to 191 participating active employees and 4 employees on long-term disability and $330,000 related to 115 eligible retirees. The 1993 cost includes $993,000 related to 184 participating active employees and 4 employees on long-term disability and $357,000 related to 125 eligible retirees. The 1992 cost includes $1,011,000 related to 183 participating active employees and $348,000 related to 119 eligible retirees.
POSTRETIREMENT BENEFITS: The Company accrues expected costs of providing postretirement benefits to employees, their beneficiaries and covered dependents in accordance with Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," (SFAS No. 106). The Company adopted the provisions of SFAS No. 106 in the first quarter of 1993. The estimated accumulated postretirement benefit obligation as of January 1, 1993 was approximately $4,822,000. This amount, reduced by applicable income tax benefits, was charged to operations in the first quarter of 1993 as the cumulative effect of a change in accounting principle. The annual net postretirement benefit cost was approximately $510,000 for 1994 and $483,000 in 1993.
At December 31, 1994, December 31, 1993 and January 1, 1993 the discount rates used in determining the actuarial present value of the accumulated postretirement benefit obligation were 9%, 7.5% and 8.5%, respectively.
(11) RELATED PARTY TRANSACTIONS: - - - --------------------------------------------------------------------------------
During 1994, the Company used a real estate complex (the Complex) owned directly or indirectly by certain stockholders and members of the Board of Directors for Company-sponsored seminars, the accommodation of business guests, the housing of personnel attending corporate meetings and for other general business purposes. In 1994, in connection with the Company's termination of usage, the Company paid $662,000 on account of the business use of such property, and an additional $300,000 as a partial reimbursement of deferred maintenance costs. The Company incurred expenses for its use of the Complex of $635,000 in 1993 and $611,000 in 1992.
John F. Dorn resigned as an executive officer and director of the Company in 1993. The Company agreed to pay John F. Dorn his salary at time of resignation through September 30, 1996. In addition, the Company provided certain other benefits and services to Mr. Dorn. The present value of the severance package was estimated at $500,000, which amount was recorded as an expense and a liability at December 31, 1993.
(11) RELATED PARTY TRANSACTIONS (CONT'D): - - - --------------------------------------------------------------------------------
In March 1994, the Company sold certain non-strategic oil and gas properties to an entity controlled by John F. Dorn and another former executive officer of the Company for net proceeds, after costs of sale and purchase price adjustments, of $3,661,000. The Company established the sales price based upon an opinion from an independent third party. The purchasers financed 100% of the purchase price with a loan bearing interest at the rate of prime plus 1%. The loan was secured by a mortgage on the properties and personal guarantees of the purchasers. The Company participated as a lender in the loan in the amount of approximately $800,000. In addition, the Company agreed to subordinate to the other lender its right of payment of principal on default. The purchasers have separately agreed with the Company that certain options to purchase company stock will be cancelled to the extent that the Company's participation in the loan is not repaid in full. Collectively, the purchasers have options to purchase 275,000 shares of the Company's Common Stock at $3.00 per share and 275,000 shares at $5.00 per share.
(12) COMMITMENTS AND CONTINGENCIES: - - - --------------------------------------------------------------------------------
Future rental payments for office facilities and equipment under the remaining terms of noncancelable leases are $1,619,000, $1,138,000, $961,000, $969,000 and $1,002,000 for the years ending December 31, 1995 through 1999, respectively.
Net rental payments applicable to exploration and development activities and capitalized in the oil and gas property accounts aggregated $851,000 in 1994, $688,000 in 1993 and $874,000 in 1992. Net rental payments charged to expense amounted to $3,512,000 in 1994, $3,098,000 in 1993 and $3,112,000 in 1992. Rental payments include the short-term lease of vehicles. None of the leases are accounted for as capital leases.
The Company, in the ordinary course of business, is a party to various legal actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, liquidity or results of operations.
(13) FINANCIAL INSTRUMENTS: - - - --------------------------------------------------------------------------------
The Company is exposed to off-balance-sheet risks associated with energy swap agreements arising from movements in the prices of oil and natural gas and from the unlikely event of non-performance by the counterparty to the swap agreements.
In order to hedge against the effects of declines in oil and natural gas prices, the Company enters into energy swap agreements with third parties and accounts for the agreements as hedges based on analogy to the criteria set forth in Statement of Financial Accounting Standards No. 80, "Accounting for Futures Contracts." In a typical swap agreement, the Company receives the difference between a fixed price per unit of production and a price based on an agreed-upon third party index if the index price is lower. If the index price is higher, the Company pays the difference. The Company's current swaps are settled on a monthly basis. For the years ended December 31, 1994, 1993 and 1992, the Company incurred swap gains (losses) of $1,810,000, $(2,050,000) and $(1,642,000), respectively.
The following table indicates outstanding energy swaps of the Company which were in place at December 31, 1994:
(13) FINANCIAL INSTRUMENTS: - - - --------------------------------------------------------------------------------
OPTION AGREEMENT. In 1993, under another agreement (the Option Agreement), the Company paid a premium of $516,000 in conjunction with the closing of the Enron loan agreement. The payment of this premium gave Forest the right to set a floor price of $1.70 per MMBTU on a total of 18,400 BBTU of natural gas over a five year period commencing January 1, 1995. In order to exercise this right to set a floor, the Company must pay an additional premium of 10CENTS per MMBTU, effectively setting the floor at $1.60 per MMBTU. The option agreement is broken into five calendar year periods with the option for each calendar year expiring four trading days prior to the last trading day for the January NYMEX contract for that year. The premium of $516,000 related to the Option Agreement was recorded as a long-term asset and will be amortized as a reduction to oil and gas income beginning in 1995 based on the volumes involved.
Set forth below is the estimated fair value of certain on and off-balance sheet financial instruments, along with the methods and assumptions used to estimate such fair values as of December 31, 1994:
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLES AND ACCOUNTS PAYABLE: The carrying amount of these instruments approximates fair value due to their short maturity.
NONRECOURSE SECURED LOAN: The fair value of the Company's nonrecourse secured loan has been estimated as approximately $58,684,000 by discounting the projected future cash payments required under the agreement by 14.45%.
PRODUCTION PAYMENT OBLIGATION: The fair value of the Company's production payment obligation has been estimated as approximately $17,405,000 by discounting the projected future cash payments required under the agreement by 12.5%.
SENIOR SUBORDINATED NOTES The fair value of the Company's 11 1/4% Subordinated Notes was approximately $91,000,000, based upon quoted market prices for the same or similar issues.
ENERGY SWAP AGREEMENTS: The fair value of the Company's energy swap agreements was approximately $7,673,000, based upon the estimated net amount the Company would receive to terminate the agreements.
(14) MAJOR CUSTOMERS: - - - --------------------------------------------------------------------------------
The Company's sales of oil and natural gas to individual customers which exceeded 10% of the Company's total sales (exclusive of the effects of energy swaps and hedges) were:
(15) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED): - - - --------------------------------------------------------------------------------
(16) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):
The following information is presented in accordance with Statement of Financial Accounting Standards No. 69, "Disclosure about Oil and Gas Producing Activities," (SFAS No. 69).
(A) COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES - The following costs were incurred in oil and gas exploration and development activities during the years ended December 31, 1994, 1993 and 1992:
(B) AGGREGATE CAPITALIZED COSTS - The aggregate capitalized costs relating to oil and gas activities were incurred as of the dates indicated:
(16) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS ACTIVITIES (UNAUDITED) (CONT'D): - - - -------------------------------------------------------------------------------- (C) RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES - Results of operations from producing activities for 1994, 1993 and 1992 are presented below. Income taxes are different from income taxes shown in the Consolidated Statements of Operations because this table excludes general and administrative and interest expense.
(16) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONT'D): - - - -------------------------------------------------------------------------------- (D) ESTIMATED PROVED OIL AND GAS RESERVES - The Company's estimate of its proved and proved developed future net recoverable oil and gas reserves and changes for 1992, 1993 and 1994 follows. Such estimates are inherently imprecise and may be subject to substantial revisions.
The Company's presentation of estimated proved oil and gas reserves has been restated to exclude quantities attributable to future deliveries required under volumetric production payments for each of the years presented. The Company has also presented, as supplemental information, proved oil and gas reserves including quantities attributable to future deliveries required under volumetric production payments. These changes were made following discussions with the Staff of the Securities and Exchange Commission.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangement, including energy swap agreements (see Note 13), but not on escalations based on future conditions.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved mechanisms of primary recovery are included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
(16) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONT'D): - - - --------------------------------------------------------------------------------
(16) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONT'D): - - - --------------------------------------------------------------------------------
(D) ESTIMATED PROVED OIL AND GAS RESERVES (CONT'D)
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS - The standardized measure of discounted net cash flows is calculated in accordance with the provisions of SFAS No. 69.
The Company's presentation of the standardized measure of discounted future net cash flows has been restated to exclude amounts attributable to future deliveries required under volumetric production payments for each of the years presented. The Company has also presented, as supplemental information, the standardized measure of discounted future net cash flows including amounts attributable to future deliveries required under volumetric production payments. These changes were made following discussions with the Staff of the Securities and Exchange Commission.
Future oil and gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, except in those instances where the sale of oil and natural gas is covered by contracts, energy swap agreements or volumetric production payments. In the case of contracts, the applicable contract prices, including fixed and determinable escalations, were used for the duration of the contract. Thereafter, the current spot price was used. Prior to December 31, 1993 the contracts included natural gas sales contracts with a company which is involved in Chapter 11 bankruptcy proceedings. Subsequent to December 31, 1993 the volumes applicable to this contract were priced at spot prices. Future oil and gas sales include the estimated effects of existing energy swap agreements as discussed in Note 13.
Future income tax expenses are estimated using the statutory tax rate of 35%. Estimates for future general and administrative and interest expenses have not been considered.
(16) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONT'D): - - - --------------------------------------------------------------------------------
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.
Undiscounted future income tax expense was $1,348,000 at December 31, 1994, $35,028,000 at December 31, 1993 and $32,718,000 at December 31, 1992.
(16) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONT'D): - - - --------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONT'D)
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:
As of April 1, 1995 the Company was receiving an average price of $1.59 per MCF and $17.25 per barrel. Based on these prices the standardized measure of discounted future net cash flows, exclusive of amounts attributable to volumetric production payments, would have been approximately $193,600,000 at December 31, 1994.
(17) SUBSEQUENT EVENTS
On April 13, 1995 the Company sold to a bank a participation interest in the Company's claim in a bankruptcy proceeding. Consideration received consisted of a $4,000,000 nonrecourse loan, in exchange for which the bank will receive, solely from the proceeds of the bankruptcy claim, an amount equal to the loan principal plus accrued interest at 16.5% per annum plus 25% of the excess, if any, of the proceeds over the loan principal and interest. The Company may, under certain conditions, limit the overall cost of financing to 23.5% per annum by exercising its option to repurchase the bank's interest in the bankruptcy claim prior to receipt of any proceeds of the claim.
On April 17, 1995, the Company signed letters of intent with The Anschutz Corporation (Anschutz) and with Joint Energy Development Investments Limited Partnership (JEDI), an affiliate of Enron Corp., in each case as described below.
The Anschutz letter of intent contemplates that Anschutz will purchase 18,800,000 shares of the Company's common stock and shares of newly-issued preferred stock that are convertible into 6,200,000 additional shares of common stock for a total consideration of $45,000,000, or $1.80 per share. The preferred stock will have a liquidation preference and will receive dividends ratably with the common stock. The investment will be made in two closings. In the first closing, expected to occur in late April 1995, Anschutz will loan the Company $9,900,000 for a term of 9 months. The loan will bear interest at 8% per annum for 16 weeks and at 12.5% per annum thereafter. The loan will be secured by unencumbered oil and gas properties owned by the Company, the preferred stock of Archean Energy Ltd. and certain other assets acceptable to Anschutz. The loan may be converted into 5,500,000 shares of Forest's common stock at Anschutz's election, but the loan must be so converted at the second closing. At the second closing, expected to occur by July 1995 following receipt of shareholder approval of the transactions then contemplated by the letters of intent, Anschutz will purchase 13,300,000 shares of common stock and the convertible preferred stock. In connection with this purchase, Anschutz will agree to certain voting, acquisition, and transfer limitations regarding shares of common stock for five years after the second closing, including (a) a limit on voting, subject to certain exceptions, that would require Anschutz to vote all shares of common stock acquierd by Anschutz in the transaction in excess of an amount equal to 19.99% of the shares of common stock then outstanding in the same proportion as all other shares of common stock are voted, (b) a limit on the number of persons associated with Anschutz that may at any time be elected as directors of the Company and (c) a limit on the acquisition of additional shares of common stock by Anschutz (whether pursuant to the exercise of the $2.10 warrants or the option received from JEDI, each as described below, or otherwise), subject to certain exceptions, that would prohibit any acquisition by Anschutz that would result in Anschutz owning 40% or more of the shares of common stock then issued and outstanding. While the foregoing limitations are in effect, Anschutz will have a minority representation on the board of directors.
The JEDI letter of intent contemplates that, at the second closing referred to above, Forest and JEDI will restructure JEDI's existing loan currently having a principal balance of approximately $62,100,000. In exchange for certain
warrants referred to below, JEDI will relinquish the net profits interest that it holds in certain Forest properties and will reduce the interest rate relating to the loan. As a result of the loan restructuring and the issuance of the warrants, the Company anticipates a reduction of the recorded amount of the related liability to approximately $45,000,000 and a reduction of interest expense of approximately $2,100,000 per annum. In addition, beginning 18 months after the second closing, the Company may prepay the loan at any time and may tender its interest in the underlying properties in full satisfaction of the loan.
The JEDI letter of intent also contemplates that, at the second closing, JEDI will receive warrants to purchase 11,250,000 shares of the Company's common stock for $2.00 per share and warrants to purchase 19,444,444 shares of common stock at $2.10 per share. The $2.00 warrants expire on the earlier of either the payment in full of the JEDI loan or December 31,2002, but no sooner than 18 months after the Second closing, except that the Company may terminate the warrants at any time beginning 18 months after the second closing if the average closing price of the common stock for 90 days preceding the termination is in excess of $2.50 per share. For the first 18 months after the second closing, the $2.00 warrants may be exercised only on the dates and in the respective numbers of shares required to be delivered by JEDI to Anschutz pursuant to the exercise of the option granted by JEDI to Anschutz, as described below. The $2.10 warrants are exercisable during the first 18 months after the second closing, subject to extension in certain circumstances to 36 months after the second closing. The letters of intent also contemplate that, at the second closing, JEDI will assign to Anschutz the $2.10 warrants and will grant to Anschutz an option to purchase up to 11,250,000 shares of common stock during the first 18 months after the second closing.
The letters of intent require the Company to pay Anschutz and JEDI certain fees and expenses in connection with the letters of intent and the transactions contemplated thereby in certain circumstances. The Anschutz letter of intent requires the Company to pay to Anschutz a fee (called a subsequent event fee) of up to $2,500,000 upon the occurence of certain events prior to the second closing (or, if the second closing does not occur, April 17, 1996), such as a merger, consolidation or other business combination between the Company and a person other than Anschutz. In the Anschutz letter of intent, the Company has agreed not to solicit proposals for transactions that would require the Company to pay a subsequent event fee and to keep Anschutz generally informed regarding the receipt and disposition by the Company of proposals regarding such transactions made by other persons.
The transactions contemplated by the letters of intent are subject to, among other things, the preparation and execution of definitive documentation satisfactory to the parties and to the approval of Forest's board of directors and certain of its creditors. The purchase by Anschutz of common stock at the second closing, the restructure of JEDI's existing loan and the transactions between Anschutz and JEDI described above are also subject to, among other things, the prior approval of Forest's shareholders and Hart-Scott-Rodino learance. While the Company's short-term and long-term liquidity would be significantly improved by the conclusion of the transactions described above, and although management believes the conditions to the closing of the transactions can be satisfied, there can be no assurance that the transactions will close on the terms and on the dates referred to above, or at all.
PART III
For information concerning Item 10







ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a). (1) FINANCIAL STATEMENTS
1. Independent Auditors' Report
2. Consolidated Balance Sheets - December 31, 1994 and 1993
3. Consolidated Statements of Operations - Years ended December 31, 1994, 1993 and 1992
4. Consolidated Statements of Shareholders' Equity - Years ended December 31, 1994, 1993 and 1992
5. Consolidated Statements of Cash Flows - Years ended December 31, 1994, 1993 and 1992
6. Notes to Consolidated Financial Statements - Years ended December 31, 1994, 1993 and 1992
(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 - Forest shall, upon written request to Daniel L. McNamara, Corporate Secretary of Forest, addressed to Forest Oil Building, Bradford, Pennsylvania 16701, provide copies of each of the following Exhibits:
Exhibit 3(i) Restated Certificate of Incorporation of Forest Oil Corporation dated October 14, 1993, incorporated herein by reference to Exhibit 3(i) to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
Exhibit 3(ii) Restated By-Laws of Forest Oil Corporation as of May 9, 1990, Amendment No. 1 to By-Laws dated as of April 2, 1991, Amendment No. 2 to By-Laws dated as of May 8, 1991, Amendment No. 3 to By-Laws dated as of July 30, 1991, Amendment No. 4 to By-Laws dated as of January 17, 1992, Amendment No. 5 to By- Laws dated as of March 18, 1993 and Amendment No. 6 to By-Laws dated as of September 14, 1993, incorporated herein by reference to
Exhibit 3(ii) to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597). Exhibit 3(ii)(a) Amendment No. 7 to By-Laws dated as of December 3, 1993, incorporated herein by reference to Exhibit 3(ii)(a) to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 3(ii)(b) Amendment No. 8 to By-Laws dated as of February 24, 1994, incorporated herein by reference to Exhibit 3(ii)(b) to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 4.1 Indenture dated as of September 8, 1993 between Forest Oil Corporation and Shawmut Bank Connecticut, National Association, incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
Exhibit 4.2 Credit Agreement dated as of December 1, 1993 between Forest Oil Corporation and Subsidiary Borrowers and Subsidiary Guarantors and The Chase Manhattan Bank (National Association), as agent, incorporated herein by reference to Exhibit 4.2 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 4.3 Amendment No. 1 dated as of December 28, 1993 relating to Exhibit 4.2 hereof, incorporated herein by reference to Exhibit 4.3 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 4.4 Amendment No. 2 dated as of January 27, 1994 relating to Exhibit 4.2 hereof, incorporated herein by reference to Exhibit 4.4 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 4.5 Amendment No. 3 dated as of June 3, 1994 relating to Exhibit 4.2 hereof, incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1994 (File No. 0-4597).
Exhibit 4.6 Security Agreement dated as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan Bank (National Association), as agent, incorporated herein by reference to Exhibit 4.5 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 4.7 Amendment No. 1 dated as of June 28, 1994 relating to Exhibit 4.6 hereof, incorporated herein by reference to Exhibit 4.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1994 (File No. 0-4597).
Exhibit 4.8 Amendment No. 2 dated as of August 31, 1994 relating to Exhibit 4.6 hereof, incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1994 (File No. 0-4597).
*Exhibit 4.9 Deed of Trust, Mortgage, Security Agreement, Assignment of Production, Financing Statement (Personal Property including Hydrocarbons), and Fixture Filing dated as of June 3, 1994 between Forest Oil Corporation and The Chase Manhattan Bank (National Association), as agent.
*Exhibit 4.10 Amendment No. 1 entered into as of June 3, 1994 relating to Exhibit 4.9 hereof.
Exhibit 4.11 Loan Agreement between Forest Oil Corporation and Joint Energy Development Investments Limited Partnership dated as of December 28, 1993, incorporated herein by reference to Exhibit 4.1 to Form 8- K for Forest Oil Corporation dated December 30, 1993 (File No. 0-4597).
Exhibit 4.12 First amendment dated as of December 28, 1993 relating to Exhibit 4.11 hereof, incorporated herein by reference to Exhibit 4.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1994 (File No. 0-4597).
Exhibit 4.13 Deed of Trust, Assignment of Production, Security Agreement and Financing Statement dated as of December 28, 1993 by and between Forest Oil Corporation and Joint Energy Development Investments Limited Partnership, incorporated herein by reference to Exhibit 4.2 to Form 8-K for Forest Oil Corporation dated December 30, 1993 (File No. 0-4597).
Exhibit 4.14 First Amendment dated as of June 15, 1994 relating to Exhibit 4.13 hereof, incorporated herein by reference to Exhibit 4.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1994 (File No. 0-4597).
Exhibit 4.15 Act of Mortgage, Assignment of Production, Security Agreement and Financing Statement dated as of December 28, 1993 between Forest Oil Corporation and Joint Energy Development Investments Limited Partnership, incorporated herein by reference to Exhibit 4.3 to Form 8-K for Forest Oil Corporation dated December 30, 1993 (File No. 0-4597).
Exhibit 4.16 Warrant Agreement dated as of December 3, 1991 between Forest Oil Corporation and The Chase Manhattan Bank (National Association), as Warrant Agent (including Form of Warrant), incorporated herein by reference to Exhibit 4.7 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1991 (File No. 0-4597).
Exhibit 4.17 Rights Agreement between Forest Oil Corporation and Mellon Securities Trust Company, as Rights Agent dated as of October 14, 1993, incorporated herein by reference to Exhibit 4.3 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
No other instruments regarding long-term debt are filed because the amount of the securities authorized thereunder do not, in any case, exceed 10% of the total assets of Forest Oil Corporation on a consolidated basis, but a copy of such instruments will be furnished to the Commission upon request.
+Exhibit 10.1 Description of Employee Overriding Royalty Bonuses, incorporated herein by reference to Exhibit 10.1 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1990 (File No. 0-4597).
+Exhibit 10.2 Description of Executive Life Insurance Plan, incorporated herein by reference to Exhibit 10.2 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1991 (File No. 0-4597).
*+Exhibit 10.3 Executive Deferred Compensation Plan.
+Exhibit 10.4 Form of non-qualified Supplemental Executive Retirement Plan, incorporated herein by reference to Exhibit 10.4 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1990 (File No. 0-4597).
+Exhibit 10.5 Form of Executive Retirement Agreement, incorporated herein by reference to Exhibit 10.5 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1990 (File No. 0-4597).
+Exhibit 10.6 Forest Oil Corporation 1992 Stock Option Plan and Option Agreement, incorporated herein by reference to Exhibit 10.7 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1991 (File No. 0-4597).
+Exhibit 10.7 Letter Agreement with Richard B. Dorn relating to a revision to Exhibit 10.5 hereof, incorporated herein by reference to Exhibit 10.11 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1991 (File No. 0-4597).
+Exhibit 10.8 Forest Oil Corporation Annual Incentive Plan effective as of January 1, 1992, incorporated herein by reference to Exhibit 10.8 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1992 (File No. 0-4597).
+Exhibit 10.9 Form of Executive Severance Agreement, incorporated herein by reference to Exhibit 10.9 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
+Exhibit 10.10 Form of Settlement Agreement and General Release between John F. Dorn and Forest Oil Corporation dated March 7, 1994, incorporated herein by reference to Exhibit 10.10 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
*Exhibit 11 Forest Oil Corporation and Subsidiaries - Calculation of Earnings per Share of Common Stock.
*Exhibit 18 Letter on change in accounting principles.
*Exhibit 24 Independent Auditors' Consent.
*Exhibit 25 Powers of Attorney of the following Officers and Directors:
Donald H. Anderson, Austin M. Beutner, Robert S. Boswell, Richard J. Callahan, Dale F. Dorn, John C. Dorn, William L. Dorn, Harold D. Hammar, David H. Keyte, James H. Lee, Daniel L. McNamara, Jeffrey W. Miller, Jack D. Riggs and Michael B. Yanney.
*Exhibit 27 Financial Data Schedule.
**Exhibit 28 Form 11-K of the Retirement Savings Plan of Forest Oil Corporation for the year ended December 31, 1994.
* Filed with this report. ** To be filed by amendment. + Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 14(c) of this report.
(b). REPORTS ON FORM 8-K
No reports on Form 8-K were filed by Forest during the last quarter of 1994.
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
FOREST OIL CORPORATION (Registrant)
Date: April 17, 1995 By: /s/ Daniel L. McNamara ------------------------ Daniel L. McNamara Secretary
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.
Signatures Title Date ---------- ----- ----
William L. Dorn* Chairman of the Board and April 17, 1995 (William L. Dorn) Chief Executive Officer (Principal Executive Officer)
Robert S. Boswell* President and Chief Financial April 17, 1995 (Robert S. Boswell) Officer (Principal Financial Officer)
David H. Keyte* Vice President and Chief April 17, 1995 (David H. Keyte) Accounting Officer (Principal Accounting Officer)
Donald H. Anderson* (Donald H. Anderson)
Austin M. Beutner* (Austin M. Beutner)
Robert S. Boswell* (Robert S. Boswell) Directors of the Registrant April 17, 1995
Richard J. Callahan* (Richard J. Callahan)
Dale F. Dorn* (Dale F. Dorn)
John C. Dorn* (John C. Dorn)
Signatures Title Date ---------- ----- ----
William L. Dorn* (William L. Dorn)
Harold D. Hammar* (Harold D. Hammar)
James H. Lee* (James H. Lee) Directors of the Registrant April 17, 1995 Jeffrey W. Miller* (Jeffrey W. Miller)
Jack D. Riggs* (Jack D. Riggs)
Michael B. Yanney* (Michael B. Yanney)
*By /s/ Daniel L. McNamara April 17, 1995 ----------------------- Daniel L. McNamara (as attorney-in-fact for each of the persons indicated)
INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION - - - ------- -----------
4.9 Deed of Trust, Mortgage, Security Agreement, Assignment of Production, Financing Statement (Personal Property including Hydrocarbons), and Fixture Filing dated as of June 3, 1994 between Forest Oil Corporation and the Chase Manhattan Bank (National Association), as agent.
4.10 Amendment No. 1 entered into as of June 3, 1994 relating to Exhibit 4.9 hereof.
10.3 Executive Deferred Compensation Plan.
11 Forest Oil Corporation and Subsidiaries - Calculation of Earnings per Share of Common Stock.
18 Letter on change in accounting principles.
24 Independent Auditors' Consent.
25 Powers of Attorney of the following Officers and Directors:
Donald H. Anderson, Austin M. Beutner, Robert S. Boswell, Richard J. Callahan, Dale F. Dorn, John C. Dorn, William L. Dorn, Harold D. Hammar, David H. Keyte, James H. Lee, Daniel L. McNamara, Jeffrey W. Miller, Jack D. Riggs and Michael B. Yanney.
27 Financial Data Schedule.