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, 1993, Forest had 187 employees, of whom 129 were salaried and 58 were hourly.
OPERATING STRATEGY
In 1991, Forest adopted a new operating strategy which focuses 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, the Company has implemented its operating strategy by acquiring estimated proved reserves of approximately 181 BCF of natural gas and 8 million barrels of oil and condensate at an average property acquisition cost of $1.08 per MCFE through December 31, 1993. (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 1993, the Company completed four major acquisitions. In two separate transactions completed in May 1993 and December 1993, the Company purchased interests in two onshore fields and seven offshore blocks from Atlantic Richfield Company (ARCO) for approximately $60,862,000. Total estimated proved reserves acquired in the ARCO acquisitions were 40.1 BCF of natural gas and 1.3 million barrels of oil. The ARCO acquisitions were financed in part by volumetric production payments. In December 1993, the Company purchased interests in two producing offshore fields in the West Cameron and Eugene Island areas (the West Cameron/Eugene Island acquisition) and three exploratory blocks from a private company for approximately $24,050,000. Total estimated proved reserves acquired as a result of the West Cameron/Eugene Island acquisition were 16.3 BCF of natural gas and 269,000 barrels of oil. Also in December 1993, the Company purchased interests in the Loma Vieja Field in south Texas from another private company for approximately $59,458,000. Total estimated proved reserves acquired as a result of the Loma Vieja acquisition were 33.9 BCF of natural gas. In addition, the Loma Vieja acquisition included 8 prospects with exploitation or exploration potential, covering 2,332 net acres. The West Cameron/Eugene Island and the Loma Vieja acquisitions were financed with proceeds of a nonrecourse secured loan, internally generated funds, and funds obtained under a bank credit facility. In other property acquisitions in 1993 Forest acquired estimated proved reserves totaling 4.4 BCF of natural gas and 102,000 barrels of oil for an aggregate purchase price of $4,700,000.
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. In total, the Company undertook 39 workover and development projects in 1993 with the following results:
Such results are not necessarily indicative of future results of the Company's workover and development projects.
The Company participates in exploration activities primarily through farmout arrangements. The Company's farmouts enable Forest to participate in its exploration prospects without incurring additional exploration costs, although with a reduced ownership in each prospect. During 1993, the Company entered into farmout agreements covering 27 prospects, pursuant to which 14 wells were drilled resulting in 9 commercially productive properties. For further information concerning the Company's farmout activity, see Item 2.

ITEM 2. PROPERTIES
Forest's principal 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 19 of Notes to Consolidated Financial Statements.
Since January 1, 1993, 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 three years ended December 31, 1993:
Net production reported by CanEagle for its fiscal year ended September 30, 1993 was 2.1 BCF of natural gas and 281,000 barrels of oil. The Company's investment in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
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 three years ended December 31, 1993 for Forest and its wholly-owned subsidiaries:
Average sales prices received by CanEagle for its fiscal year ended September 30, 1993 were $1.77 CDN per MCF of natural gas and $20.77 CDN per barrel of oil. CanEagle's natural gas production was sold under long-term contracts and its oil production was sold on the spot market. The average production cost per MCFE reported by CanEagle was $.49 CDN per MCFE. The Company's investment in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
PRODUCTIVE WELLS
The following summarizes total gross and net productive wells of the Company and its wholly-owned subsidiaries at December 31, 1993, all of which are in the United States:
At September 30, 1993, CanEagle had 33 net productive oil wells and 32 net productive gas wells. The Company's investment in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
DEVELOPED AND UNDEVELOPED ACREAGE
Forest and its wholly-owned subsidiaries held acreage as set forth below at December 31, 1993 and 1992. 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, 5 and 7 of Notes to Consolidated Financial Statements.
During 1993, the Company's gross and net developed acreage increased approximately 12% and 92%, respectively, primarily as a result of property acquisitions. The Company's gross and net undeveloped acreage decreased 35% and 27%, respectively, because the acquisitions made during the year were more than offset by 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 13% of the Company's total net undeveloped acreage is under leases that have terms expiring in 1994, if not held by production, and another approximately 44% of net undeveloped acreage will expire in 1995 if not also held by production.
At September 30, 1993, CanEagle held 31,705 gross developed acres, 8,179 net developed acres, 95,847 gross undeveloped acres and 33,478 net undeveloped acres. The Company's investment in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
DRILLING ACTIVITY
Forest and its wholly-owned subsidiaries owned interests in net exploratory and net development wells for the three years ended December 31, 1993 as set forth below. This information does not include wells drilled under farmout agreements as discussed below.
During its fiscal year ended September 30, 1993, CanEagle drilled 2.1 productive net development wells in Canada. The Company's investment in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
FARMOUT AGREEMENTS
Forest entered into farmout agreements with respect to 27 exploration prospects during 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. Eleven of the farmouts cover onshore prospects and 16 cover prospects located in the Gulf of Mexico.
Fourteen of the 27 farmout prospects were drilled during 1993, resulting in nine productive properties. Forest retained overriding royalty interests ranging from 2.083% to 12.5% before payout, increasing to interests ranging from a 10% overriding royalty interest to a 40% net working interest after payout. One additional well was drilled and commenced production in 1994; the Company anticipates that the 12 remaining undrilled farmouts will be drilled during 1994.
During 1993, the Company entered into an exploration agreement under which a third party agreed to drill a minimum of six additional exploratory wells offshore. The Company retained overriding royalty interests in these prospects of between 8.33% and 12.5% with the option to convert to working interests ranging from 25% to 33 1/3% after payout of the first well on each prospect. Four of these six wells were drilled by the end of 1993, resulting in one productive well. The remaining two wells are scheduled to be drilled in the first half of 1994.
The Company intends to continue to seek farmouts of exploration prospects when they can be arranged on terms that are believed to be favorable.
During its fiscal year ended September 30, 1993, CanEagle concluded two farmout agreements under which two successful gas wells were drilled and completed. The Company's investment in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
PRESENT ACTIVITIES
At December 31, 1993, Forest and its wholly owned subsidiaries had three development wells that were in the process of being drilled. All three wells were determined to be productive in January 1994 and are currently being tested. There was one well being drilled under a farmout agreement at year- end, which was subsequently completed as a producing well.
At September 30, 1993 CanEagle had one development well that was in the process of being drilled. This well was determined to be a gas well and commenced production in November 1993. The Company's investment in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
DELIVERY COMMITMENTS
At December 31, 1993 Forest and its wholly-owned subsidiaries were obligated to deliver approximately 36.3 BCF of natural gas and 479,000 barrels of oil under the terms of volumetric production payments. The delivery commitments cover approximately 35% and 12% 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 .8 BCF of natural gas under existing long-term contracts. For further information concerning the Company's production payment agreements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 7 of Notes to Consolidated Financial Statements.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
The Company has 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, 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, will have a material adverse effect, either individually or in the aggregate, on the financial condition of the Company.
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.
YEARS WITH NAME (A) AGE FOREST OFFICE (B) -------- --- ---------- ----------
William L. Dorn* 45 22 Chairman of the Board and Chairman of the Executive Committee since July 1991. Member of the Executive Committee since August 1988. President from February 1990 until November 1993 and Chief Executive Officer since February 1990. Executive Vice President from August 1989 until February 1990, and prior thereto Vice President. Member of the Royalty Bonus Committee since August 1991.
Robert S. Boswell* 44 5 President since November 1993. Vice President from May 1991 until November 1993 and Chief Financial Officer since May 1991. Financial Vice President from September 1989 until May 1991. Member of the Executive Committee since July 1991, member of the Royalty Bonus Committee since August 1991. Chief Financial Officer of Bovaird Supply Company, Inc., from January 1988 until September 1989.
Bulent A. Berilgen 45 9 Vice President of Operations since December 1993. Prior thereto Vice President - Engineering and Development since January 1992. Prior thereto Regional Reservoir Engineer.
Kenton M. Scroggs 41 11 Vice President since December 1993 and Treasurer since May 1988. Prior thereto Assistant Treasurer. Member of the Administrative Committee of the Company's Retirement Savings Plan and Chairman of the Board of Trustees of the Company's Pension Trust.
YEARS WITH NAME (A) AGE FOREST OFFICE (B) -------- --- ---------- ----------
Forest D. Dorn 39 16 Vice President since February 1991 and General Business Manager since December 1993. Prior thereto General Manager - Operations since January 1992. Prior thereto Assistant Division Manager of the Southern Division. Member of the Contributions Committee.
David H. Keyte 37 6 Vice President and Chief Accounting Officer since December 1993. Prior thereto Corporate Controller since January 1989. Prior thereto Manager of Tax. Chairman of the Administrative Committee of the Company's Retirement Savings Plan and member of the Board of Trustees of the Company's Pension Trust.
Daniel L. McNamara 48 22 Secretary and Corporate Counsel since January 1991. Prior thereto Assistant Secretary and Associate Corporate Counsel.
Joan C. Sonnen 40 4 Controller since December 1993. Prior thereto Director of Financial Accounting and Reporting since April 1991 and Manager of Financial Systems and Reporting since July 1989. Prior thereto a principal with Arthur Young & Company.
- ------------- *Also a Director
(A) William L. Dorn and Forest D. Dorn are brothers, and they are nephews of John C. Dorn, a director of the Company.
(B) The term of office of each officer is one year from the date of his or her election immediately following the last annual meeting of shareholders and until the officer's respective successor has been elected and qualified or until his or her earlier death, resignation or removal from office whichever occurs first. Each of the named persons has held the office indicated since the last annual meeting of shareholders, except as otherwise indicated.
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.
As of March 1, 1994, 27,942,755 shares of Common Stock were held by 2,109 recordholders and 1,244,715 Warrants were held by 88 recordholders.
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.
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 restriction in the Credit Agreement, the Company currently has the ability to pay dividends in the approximate amount of $1,920,000, assuming the cash dividend on the $.75 Preferred Stock declared by the Company in February 1994 is paid in May 1994. There is no assurance that Forest will pay any dividends. For further information on Forest's ability to pay cash 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, 6, 9 and 10 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.
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 1, 1994, 2,880,973 shares of $.75 Convertible Preferred Stock were held by 86 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 1992, 1993 or in the first quarter of 1994.
On March 15, 1994, the last reported sales price of the Common Stock as quoted on the NASDAQ/NMS was $3-11/16 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 15, 1994, the last reported sales price of the Warrants as quoted on the NASDAQ/NMS was $1-7/8 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 15, 1994, the last reported sales price of the $.75 Convertible Preferred Stock as quoted on the NASDAQ/NMS was $14-1/4 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, entitle 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, 1993. 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 $21,213,000 in 1993 compared to net earnings of $7,298,000 in 1992 and a net loss of $25,348,000 in 1991. 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). Total revenue less operating expenses (consisting of oil and gas production expense and expensed general and administrative costs) 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 effects of cumulative changes in accounting principles related to postretirement benefits and income taxes. The 1992 results improved significantly compared to 1991 due to approximately $24,043,000 of net earnings associated with the ONEOK settlement in December 1992 and because there was no writedown of the carrying value of the Company's oil and gas properties required in 1992 by SEC regulations. The 1991 loss included a writedown of the Company's oil and gas properties of $22,400,000 on an after-tax basis, offset by an extraordinary gain of $9,502,000 (net of income taxes of $4,895,000) on extinguishment of debt.
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 1993, 1992 and 1991.
REVENUE. Total revenue increased 39% to $105,148,000 in 1993 from $75,645,000 in 1992, primarily due to increased production from newly-acquired properties. Total revenue increased by 8% to $75,645,000 in 1992 from $69,897,000 in 1991. The increase is due primarily to increased production volumes, despite a decrease in average sales prices for both oil and natural gas.
Oil and gas sales increased to $102,883,000 from $76,847,000, or by approximately 34% in 1993 from 1992, primarily due 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.
Oil and gas sales increased to $76,847,000 from $68,876,000 or by approximately 12% in 1992 from 1991. The increase primarily resulted from increased production volumes, despite a decrease in average sales prices for both oil and natural gas. In 1992, oil production volumes were up 71% and natural gas production volumes were up 22% compared to 1991. The increased volumes were primarily the result of property acquisitions in 1992. The increase in revenue attributable to the increased production was partially offset by a 28% decrease in the average sales price for oil and an 8% decrease in the average sales price for natural gas.
The production volumes and average sales prices for the three years ended December 31, 1993 for Forest and its wholly-owned subsidiaries were as follows:
Natural gas sold pursuant to volumetric production payment agreements and other long-term fixed price contracts represented approximately 46% of production in 1993 versus 33% in 1992 and 28% in 1991. 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 increase experienced by Forest in natural gas sold under long-term fixed price contracts in 1993, 1992 and 1991 was the result of the Company entering into volumetric production payment agreements.
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. The 1991 amount of $1,021,000 included interest income of $1,314,000 on cash balances invested in short-term investments and $2,032,000 of revenue associated with a favorable ruling by a Texas court with respect to severance tax on take-or-pay settlements, offset by $1,550,000 provided for uncollectible receivables and $850,000 of refund claims which were abandoned.
OIL AND GAS PRODUCTION EXPENSE. 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. Oil and gas production expense increased 14% to $14,276,000 in 1992 compared to $12,548,000 in 1991 due to increased production. In 1993, production expense was approximately $.39 on an MCFE basis, compared to $.38 in 1992 and $.43 in 1991. The decrease in 1992 compared to 1991 was the result of cost-savings measures coupled with economies of scale achieved when certain fixed operating costs were spread over a larger asset base.
GENERAL AND ADMINISTRATIVE EXPENSE. 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. General and administrative expense for 1992 increased 27% to $12,088,000 from $9,541,000 in 1991, reflecting a decrease in the capitalization rate applied to total overhead costs. The decrease in the capitalization rate was the result of a decrease in the percentage of employees' time spent working directly on exploration and development projects. The capitalization rate remained relatively constant from 1992 to 1993.
The Company has devoted significant effort to reducing total overhead costs. Total overhead costs, including amounts related to exploration and development activities, were $19,561,000 in 1993, $19,237,000 in 1992 and $23,292,000 in 1991. 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 decrease in total overhead costs in 1992 from 1991 was primarily due to reductions in workforce which occurred during 1991. The following table summarizes the total overhead costs incurred during the periods, including retirement benefits for executives and directors:
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. Additional expense of $950,000 was recorded in 1991 to reflect the accrual of amounts due to certain Retirees upon resignation as directors of the Company.
RESTRUCTURING. Restructuring expense in 1991 includes the costs of the Company's implementation of a reorganization and consolidation plan. Costs recorded in 1991 of approximately $3,585,000 related to reductions in workforce and a consolidation of the Company's technical staff, reduced by a credit recognized upon curtailment of the Company's defined benefit pension plan.
INTEREST EXPENSE. 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. Interest expense of $27,800,000 in 1992 increased $4,494,000 or 19% compared to 1991 due to increased indebtedness in the form of a dollar-denominated production payment related to the acquisition of properties.
DEPRECIATION AND DEPLETION EXPENSE. 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. Depreciation and depletion expense increased 22% to $46,624,000 in 1992 from $38,229,000 in 1991 due to increased production volumes despite a slightly lower rate per MCFE. The depletion rate was $1.19 per MCFE for U.S. production in 1993 compared to corresponding rates of $1.21 for U.S. production and $1.19 for Canadian production in 1992 and $1.28 for U.S. production and $1.37 for Canadian production in 1991.
IMPAIRMENT OF OIL AND GAS PROPERTIES. The Company recorded a writedown of its oil and gas properties of $34,000,000 in 1991 due to the poor results of the Company's 1990 exploration program and depressed natural gas prices.
Additional writedowns of the full cost pools may be required if prices 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 additional reserves, if any.
The average spot market price received by the Company for Gulf Coast natural gas production was approximately $2.48 per MCF at December 31, 1993. The West Texas Intermediate price for crude oil received by the Company was $12.00 per barrel at December 31, 1993. The average Gulf Coast spot price received by the Company for natural gas declined from $2.48 per MCF at December 31, 1993 to $2.46 per MCF at March 1, 1994. The West Texas Intermediate price for crude oil increased from $12.00 per barrel at December 31, 1993 to $13.00 per barrel at March 1, 1994.
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). On September 30, 1992 FCID sold its Canadian assets and related operations to CanEagle for approximately $51,250,000 in Canadian funds ($41,000,000 U.S.). An independent third party financed the purchase by CanEagle. In the transaction, FCID received cash of approximately $28,000,000 CDN ($22,400,000 U.S.), net of expenses, and provided financing to the third party in the aggregate principal amount of $22,000,000 CDN ($17,600,000 U.S.).
CanEagle's capital was restructured in 1993. At December 31, 1993, the Company's ownership interest in CanEagle consisted of 15,400,000 shares of Class A Preferred Shares and 1,400,000 shares of Class B Preferred Shares of CanEagle and a $6,000,000 CDN subordinated debenture.
Substantial uncertainty exists regarding whether CanEagle is a going concern due to a required principal payment of $16,300,000 on its Senior Debenture due June 30, 1994. CanEagle is in the process of refinancing the Senior Debenture with its lender, but there is no assurance that such refinancing can be completed on mutually acceptable terms prior to the due date.
No gain was recognized as a result of the CanEagle transaction because collection of the remaining sales price was not reasonably assured. Due to its continuing financial interest in CanEagle, the Company is accounting for its investment in CanEagle under the equity method. Accordingly, losses will be recognized to the extent that such losses exceed (a) amounts attributable to securities subordinate to the Company's interest, and (b) a basis difference of $780,000 CDN attributable to the 1993 capital restructuring of CanEagle. Under this method, no portion of the CanEagle loss was required to be recorded by the Company in 1993.
Earnings related to the Company's interest in CanEagle will be recognized only if realization is assured. Accordingly, amounts received as interest on the subordinated note during 1993 (approximately $540,000 CDN) were recorded as a reduction of the Company's investment in and advances to CanEagle. There were no dividends received in 1993.
The excess of the carrying value of properties sold over the cash received, or approximately $16,451,000 U.S. at December 31, 1993, represents Forest's investment in CanEagle.
CHANGES IN ACCOUNTING
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 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 $480,000 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.
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW. Historically, one of the Company's primary sources of capital has been net cash provided by operating activities, which has varied dramatically in the last three years. The majority of the increases and decreases in net cash provided by operating activities is attributable to increases and decreases in oil and gas revenue. While expenses associated with operations have been relatively stable, revenue from operations has varied dramatically each year 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, 1993, 1992 and 1991:
SHORT-TERM LIQUIDITY AND WORKING CAPITAL DEFICIT. In December 1993, the Company entered into a secured master 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, which amount is subject to semi- annual redetermination, and up to $17,500,000 for working capital and general corporate purposes. 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. Borrowings under the Credit Facility bear interest at the Chase base rate plus 3/8 of 1% or 1,2,3 or 6 month LIBOR plus 1 and 5/8%, payable quarterly. A commitment fee of 1/2 of 1% is charged on unused availability. 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, 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, 1993 the outstanding balance under this facility was $25,000,000.
Due to the significant capital requirements of acquisition and development activities undertaken in December 1993, the Company reported a working capital deficit of $14,496,000 at December 31, 1993. The Company did not meet the test imposed by the working capital covenant of the Credit Facility; compliance with this covenant was waived by Chase at December 31, 1993. The deficit was funded in the first quarter of 1994 primarily by additional borrowings of $9,000,000 under the Credit Facility, net proceeds of $2,600,000 from the sale of non- strategic oil and gas properties, and a short-term loan from The Chase Manhattan Bank, N.A. of $4,000,000 secured by a pledge of the Company's CanEagle securities. These cash inflows, in addition to cash provided by operating activities, enabled the Company to meet its obligations with respect to principal and interest payments and other short-term obligations. The Company currently has no additional borrowing capacity under the Credit Facility.
The Company continues to explore additional sources of short-term liquidity to fund its working capital deficits, including an increase in the Credit Facility, sale of additional non-strategic properties and excess equipment, monetization of its investment in and advances to CanEagle and other measures. Expected increases in operating
cash flows from recent property acquisitions are also expected to improve the Company's short-term liquidity, although there can be no assurance that this will be the case due to uncertainties in the markets for oil and natural gas and the unpredictability inherent in oil and gas operations.
LONG-TERM LIQUIDITY. Since 1991, the Company has taken several significant steps to improve its long-term liquidity. In 1991, the Company consummated its recapitalization pursuant to which the Company's outstanding debt and preferred stock were restructured in order to reduce its fixed financial costs. The Company also undertook certain actions in 1991 to implement its operating strategy, to control and reduce its operating costs, and to improve its operating efficiency. The Company continues to devote significant efforts in these areas.
On December 24, 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 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.
VOLUMETRIC PRODUCTION PAYMENTS. Through December 31, 1993, the Company received approximately $134,705,000 (net of fees) from the sale of volumetric production payments and, in return, committed to deliver from the subject properties approximately 77.4 BCF of natural gas and 770,000 barrels of oil to entities associated with Enron Corp. (Enron). As of December 31, 1993, the volumes remaining to be delivered were approximately 36.3 BCF of natural gas and 479,000 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 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 $67,228,000 as of December 31, 1993. 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 a dollar-denominated production payment sold in February 1992 in connection with the acquisition of the Harbert Energy Corporation properties, the Company is required to make payments based on the net proceeds, as defined, from certain subject properties.
As of December 31, 1993, the Enron loan of $57,400,000, which bears annual interest at the rate of 12.5%, was recorded at $53,101,000 to reflect the conveyance to the lender of a 20% interest in the net profits, as defined, of the Loma Vieja properties. 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 is that 1994 payments will reduce the recorded liability by approximately $983,000. 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.
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, 1993 the remaining recorded liability was $21,305,000. Under the terms of the dollar-denominated 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's current estimate is that 1994 payments will
reduce the recorded liability by approximately $3,388,000. Properties to which approximately 7% 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, 1993 the Company had natural gas swaps for an aggregate of approximately 30 MMBTU per day of natural gas during 1994 at fixed prices ranging from $1.90 to $2.30 per MMBTU. At December 31, 1993 the Company had no oil swaps in place.
OPTION AGREEMENT. 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 gives Forest the right to set a floor price of $1.70 per MMBTU on a total of 18.4 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 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.
TRIGGER AGREEMENTS. Two trigger agreements were entered into during 1993. Under a "trigger" agreement, the Company agrees to enter into a swap agreement at a later date based upon a specified margin over an agreed-upon third party index. One agreement originally entered into in July 1993 obligated the Company to enter into a gas swap arrangement in 1994. This agreement was terminated in December 1993, in exchange for which the Company will pay $0.2675 per MMBTU on 5,000 MMBTU per day for each contract month, which equates to $488,000. The discounted value of this amount, or $457,000, has been recorded as expense and as a liability at December 31, 1993 and will be paid in monthly installments of approximately $41,000 during 1994. The second trigger agreement was converted into a natural gas swap and is included in the natural gas swaps discussed above. The Company currently has no open trigger agreements.
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 62% of its natural gas production and 15% of its oil production will not be subject to price fluctuations from January 1994 through December 1994. Existing hedge agreements currently cover approximately 42% of the Company's natural gas production and 12% of its oil production for the year ending
December 31, 1995. Currently, it is the Company's intention to commit no more than 75% of its production to such arrangements at any point in time. See "Hedging Program" below.
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 24 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 dedicated 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. In 1991, the Company implemented its capital investment strategy of acquiring proved properties. During 1992 and 1993, the Company completed six major acquisitions under this strategy. The Company's expenditures for property acquisition, exploration and development for the past three years, including overhead related to these activities which was capitalized, were as follows:
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 of the acquisitions for financial accounting purposes, 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.
For the year ended December 31, 1993, finding costs were $1.26 per MCFE and reserve replacement was 271%. This compares to $1.20 and 235% in 1992 and $1.56 and 79% in 1991. Finding costs are the total costs incurred in oil and gas acquisition, exploration and development activities, including capitalized overhead, for any period, divided by net additions to proved reserves on an MCFE basis (including revisions, extensions and discoveries and purchases of reserves in place) for such period. Reserve replacement represents estimated proved reserve additions as a percentage of production before taking into account sales of oil and gas reserves in place.
It is currently anticipated that the Company's 1994 expenditures for exploration and development will be approximately $3,900,000, and $24,300,000, respectively, including capitalized overhead of $900,000 and $5,600,000, respectively. Under the terms of the Enron loan, 80% of direct development expenditures on the properties subject to the loan reduce payments which would otherwise be due; however, planned levels of capital expenditures may still be restricted if the Company experiences lower than anticipated net cash provided by operations or other liquidity problems.
During 1994, the Company intends to aggressively pursue a strategy of acquiring reserves; 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; the issuance of net profits interests; sales of non-strategic properties, prospects and technical information; joint venture financing; the issuance of common or preferred equity of the Company; sale of production payments and other nonrecourse financing; as well as additional bank financing. Availability of these sources of capital will depend upon a number of factors, some of which are beyond the control of the Company.
DIVIDENDS. To increase liquidity and fund a portion of its capital budget, the Company deferred payment of dividends on its $15.75 Redeemable Preferred Stock and its $2.125 Convertible Preferred Stock throughout 1991. All dividend arrearages were eliminated at the end of 1991 when the $15.75 Redeemable Preferred Stock and $2.125 Convertible Preferred Stock were recapitalized.
Throughout most of 1991, the Company did not have the legal ability under the NYBCL to pay dividends. Upon completion of the recapitalization, this restriction was removed and the Company once again has the legal ability under the NYBCL to pay dividends, although it is subject to certain restrictive provisions in the Indenture executed in connection with the 11 1/4% Senior Subordinated Notes due 2003 and in the Credit Facility. The Company was required to pay dividends, when and if declared, on its $.75 Convertible Preferred Stock in shares of Common Stock through 1993. On February 1, 1994, a cash dividend of $.1875 on its $.75 Convertible Preferred Stock was paid to holders of record on January 14, 1994. On February 20, 1994 the Board of Directors declared a cash dividend of $.1875 on the $.75 Convertible Preferred Stock, payable May 1, 1994 to holders of record on April 8, 1994. For further information concerning dividends, see Item 5. Market for Registrant's Common Equity and Related Stockholder Matters and Notes 4, 6, 9 and 10 of Notes to Consolidated Financial Statements.
OTHER MATTERS
GAS BALANCING. It is customary in the industry for various working interest partners to produce more or less than their entitlement share of natural gas from time to time. During 1993, the Company's net overproduced position decreased from approximately 13 BCF to approximately 10 BCF. In 1992, the Company's net overproduced position decreased from approximately 16 BCF to approximately 13 BCF. In 1991, the Company's net overproduced position did not change appreciably due to the offseting effects of gas balancing settlements and production in excess of entitlements. The Company has entered into gas balancing agreements for most of its imbalance position and currently estimates that approximately 3 BCF and 2 BCF will be repaid in 1994 and 1995 under such agreements. In the absence of a gas balancing agreement, the Company is unable to determine when its partners may choose to make up their share of production. If and when the Company's partners do make up their share of production, the Company's deliverable natural gas volumes could decrease, adversely affecting revenue and cash flow. For futher information, see Note 1 of Notes to Consolidated Financial Statements.
UNFUNDED PENSION LIABILITIES. In 1993, in response to market conditions, the Company lowered from 9% to 7.5% 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 recorded a liability of $3,038,000 representing the unfunded liabilities of these plans and a corresponding decrease 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 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.
NET OPERATING LOSS AND TAX CREDIT CARRYFORWARDS. At December 31, 1993, the Company estimated that for United States federal income tax purposes, it had consolidated net operating loss carryforwards of $28,439,000, depletion carryforwards of approximately $20,174,000 and investment tax credit carryforwards of approximately $3,885,000. 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, 1993, 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, 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, 1993, that there will be no significant limitation on the Company's ability to use these net operating loss carryforwards or investment tax credit carryforwards.
CHANGE IN FEDERAL CORPORATE INCOME TAX RATES. 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 benefit at December 31, 1993 on the loss from continuing operations was approximately $167,000 less than it would have been without such increase in the tax rate. However, due to limitations on the recognition of deferred tax assets under FAS 109, the total tax benefit at December 31, 1993, including the tax benefit on the extraordinary loss on extinguishment of debt, is unaffected by the tax rate increase. The impact of the tax rate increase on the Company's total tax expense will be recognized when future taxable income absorbs the present unrecognized deferred tax asset.
ACCOUNTING POLICIES. In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" (SFAS No. 112). This statement requires the accrual of the estimated cost of certain postemployment benefits provided to former employees. SFAS No. 112 is effective for years beginning after December 15, 1993. The initial effect of applying this statement is to be accounted for as a cumulative effect of a change in accounting principle. The Company has not determined precisely what effect, if any, the adoption of SFAS No. 112 will have on its financial statements, but believes the effect will be immaterial because the Company has already recorded liabilities for any of the affected costs that would be significant.
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, 1993 and 1992, 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, 1993. 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, 1993 and 1992, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1993 in conformity with generally accepted accounting principles.
As discussed in Notes 8 and 13 to the 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
Denver, Colorado February 22, 1994
FOREST OIL CORPORATION CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS
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.
(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. The Company's investment in CanEagle Resources Corporation (CanEagle) is accounted for using the equity method (See Note 3).
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. Separate cost centers are maintained for each country in which the Company has operations. 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. Costs applicable to each cost center, including capitalized costs as wells as estimated costs of future development, surrender and abandonment, are depleted using the units of production method. Unusually significant investments in seismic data and unproved properties, including related capitalized interest costs, are not depleted pending the determination of the existence of proved reserves and the commencement of sales from the properties. As of December 31, 1993 and 1992, there were undeveloped property costs of $41,216,000 and $18,306,000, respectively, in the United States which were not being depleted, all of which relate to property acquisitions in 1992 and 1993. At December 31, 1991 there were no costs in any cost centers which were not subject to depletion.
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:
UNITED STATES CANADA ------------- ------
1993 $ 1.19 - 1992 1.21 1.19 1991 1.28 1.37
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 of each of the cost centers, the accompanying financial statements include a provision for impairment of oil and gas property costs of $15,000,000 in the United States and $19,000,000 in Canada in 1991. There was no impairment of oil and gas property costs required to be recorded in 1993 or 1992.
No gain or loss is recognized on the sale of oil and gas properties except in the case of properties involving significant remaining reserves. Proceeds from sales of insignificant reserves and undeveloped properties are applied to reduce the costs in the cost centers.
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.
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONT'D): - --------------------------------------------------------------------------------
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 tax bases and financial reporting bases of all other assets and liabilities. Temporary differences are principally the result of certain development, exploration and other costs which are deducted for income tax purposes but capitalized for financial accounting purposes.
FOREIGN CURRENCY TRANSLATION - Balance sheet accounts of Canadian activities are translated into United States dollars using the year-end exchange rates. Income and expense items have been translated at rates applicable during each year. Adjustments resulting from these translations are accumulated in a separate component of shareholders' equity.
GAS REVENUE - The Company uses the sales method of accounting for amounts received from natural gas sales. Under this method, all proceeds from production credited to the Company are recorded as revenue until such time as the Company has produced its share of related estimated remaining reserves. Thereafter, additional amounts received are recorded as a liability.
As of December 31, 1993 the Company had produced approximately 10 BCF more than its entitled share of production. The undiscounted value of this imbalance is approximately $17,000,000 using the lower of the price received for the natural gas, the current market price or the contract price, as applicable. Amounts received for approximately 7 BCF of this production have been recorded as revenue and as reductions of the Company's reserve quantities and reserve values described in Note 19. Amounts received for the remaining 3 BCF of this production have been recorded as a liability as this volume exceeds the Company's share of the related estimated remaining reserves. The liability is recorded in accordance with the settlement provisions of the applicable gas balancing agreements and amounted to approximately $3,887,000 at December 31, 1993.
ENERGY SWAPS AND OTHER FINANCIAL ARRANGEMENTS - In order to hedge against the effects of declines in oil and natural gas prices, the Company enters into energy swap agreements and other financial arrangements with third parties. 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, 1993, 1992 and 1991, the Company incurred swap gains (losses) of $(2,050,000), $(1,642,000) and $3,564,000, respectively. The Company recognizes gains or losses on such agreements as adjustments to revenue recorded for the related production.
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 $2,250,000 in 1993, $2,348,000 in 1992, and $5,209,000 in 1991. Common share equivalents include, when applicable, dilutive stock options and warrants using the treasury stock method.
Fully diluted earnings per share assumes, 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) the additional dilutive effect of stock options and warrants. The effects of these assumptions were anti-dilutive in 1993 and 1991. The weighted average number of shares outstanding on a fully- diluted basis was 26,515,000 for the year ended December 31, 1992.
(2) ACQUISITIONS: - --------------------------------------------------------------------------------
On May 18, 1993 and December 10, 1993, the Company purchased interests in properties from Atlantic Richfield Company (ARCO) for approximately $60,862,000.
In conjunction with the acquisitions, the Company sold volumetric production payments from certain of the ARCO properties for approximately $40,468,000 (net of fees). On December 14, 1993, the Company purchased interests in offshore properties in the West Cameron/Eugene Island area from a private company for approximately $24,050,000. On December 30, 1993, the Company purchased interests in properties in the Loma Vieja field in south Texas for approximately $59,458,000. In conjunction with the acquisitions, the Company entered into a nonrecourse secured loan agreement for $51,600,000. The remainder of the purchase price for these two acquisitions, $31,908,000, was financed through internal funds and from funds obtained under the Company's secured master credit facility. 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 West Cameron/Eugene Island properties and the second ARCO acquisition since December 1, 1993.
On February 1, 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 consisted of payment of approximately $7,120,000 in cash (including acquisition costs), assumption by Forest of certain liabilities, and the sale of a dollar-denominated production payment which was recorded at its present value of $28,805,000. On July 31, 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). In addition, the Company issued a $2,000,000 promissory note to Transco Energy Corporation as part of the purchase price. Approximately $4,062,000 was paid in cash, including acquisition costs. 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 July 31, 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). On September 30, 1992, FCID sold its Canadian assets and related operations to 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. An independent third party financed the purchase by CanEagle. In the transaction, FCID received cash of approximately $28,000,000 CDN ($22,400,000 U.S.), net of expenses, and provided financing to the third party in the aggregate principal amount of $22,000,000 CDN ($17,600,000 U.S.).
In connection with the transaction, CanEagle issued to the third party (a) a $19,000,000 CDN senior debenture, secured by its oil and gas properties, (b) a $6,000,000 CDN subordinated debenture, secured by its oil and gas properties and subordinated to the senior debenture, (c) a $16,000,000 CDN senior subordinated note, unsecured and subordinated to the debentures, (d) convertible notes for $6,250,000 CDN, unsecured and subordinated to the debentures and the senior subordinated note, and (e) preferred stock for $4,000,000 CDN. A Canadian bank provided financing to the third party secured by a pledge of the senior debenture. Forest's financing to the third party is secured by a pledge of the subordinated debenture and the senior subordinated note. The notes received by Forest from the third party, the subordinated debenture and the senior subordinated note were due March 31, 1998 and bore interest at 9% per annum payable quarterly.
As part of the transaction, Forest retained 100% of the common equity of CanEagle and granted an option to a third party to purchase 80% of the common equity of CanEagle for nominal consideration. The original option lapsed unexercised in December 1992. Forest subsequently agreed to sell all of the common equity interest to the third party, subject to certain revisions to aspects of CanEagle's capital structure. This sale was completed on September 29, 1993 for nominal consideration.
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D): - --------------------------------------------------------------------------------
On September 29, 1993, Forest exchanged the $16,000,000 CDN senior subordinated note plus $780,000 CDN accrued interest thereon for 15,400,000 shares of Class A Preferred Shares and 1,400,000 shares of Class B Preferred Shares of CanEagle. The Class A and Class B Preferred Shares have liquidation preference rights of $1.00 CDN per share. The Class A Preferred Shares are entitled to annual fixed cumulative preferential cash dividends of $.03 per share, payable quarterly. Dividends may be paid through issuance of noninterest-bearing promissory notes due not later than September 30, 1998. Class B Preferred Shares are entitled to an annual $.03 fixed cumulative cash dividend payable only after all Class A Preferred Shares have been redeemed.
CanEagle may redeem first the Class A and then the Class B Preferred Shares at $1.00 CDN per share plus all accumulated but unpaid dividends thereon at any time subsequent to issuance, on a pro rata basis from all holders of each issue, but is required to redeem all of the then outstanding shares of both issues on or before September 30, 1998.
While any of the Class A and Class B Preferred Shares are outstanding, CanEagle is prohibited from making dividends or distributions on, or redeeming or purchasing any of its common shares, issuing any additional preferred shares, incurring any indebtedness other than as permitted under the restated articles of incorporation or undertaking certain other prohibited transactions unless unanimously approved by holders of the Class A shares.
No gain was recognized as a result of the CanEagle transaction because collection of the remaining sales price was not reasonably assured. Due to its continuing financial interest in CanEagle, the Company is accounting for its investment in CanEagle under the equity method. Accordingly, losses will be recognized to the extent that such losses exceed (a) amounts attributable to securities subordinate to the Company's interest, and (b) the basis difference of $780,000 CDN attributable to the 1993 capital restructuring of CanEagle. Under this method, no portion of the CanEagle loss was required to be recorded by the Company in 1993.
Earnings related to the Company's interest in CanEagle will be recognized only if realization is assured. Accordingly, amounts received as interest on the subordinated note during 1993 (approximately $540,000 CDN) were recorded as a reduction of the Company's investment in and advances to CanEagle. No dividends were paid on the Class A Preferred Shares in 1993.
The excess of the carrying value of properties sold over the cash received, or approximately $16,451,000 U.S. at December 31, 1993, represents Forest's investment in CanEagle.
In March 1994, the Company pledged its CanEagle securities as collateral for a $4,000,000 loan from The Chase Manhattan Bank, NA due June 1, 1994.
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D): - --------------------------------------------------------------------------------
CanEagle reports its annual results on a fiscal year ending on September 30. Condensed financial statement information for CanEagle as of September 30, 1993 and 1992 and for the year ended September 30, 1993 is as follows:
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D): - --------------------------------------------------------------------------------
Substantial uncertainty exists regarding whether CanEagle is a going concern due to the required principal payment of $16,300,000 on its Senior Debenture due June 30, 1994. CanEagle is in the process of refinancing the Senior Debenture with its lender, but there is no assurance that such refinancing can be completed on mutually acceptable terms prior to the due date. The above condensed financial statements do not include any adjustments relating to the ultimate outcome of this uncertainty.
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) Unaudited information with respect to costs incurred by CanEagle for oil and gas exploration and development activities is as follows:
(B) Unaudited information with respect to CanEagle's estimated proved oil and gas reserves at September 30, 1993 and 1992 follows. Such estimates are inherently imprecise and may be subject to substantial revisions.
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D): - --------------------------------------------------------------------------------
(C) The standardized measure of discounted future net cash flows of CanEagle, calculated in accordance with the provisions of SFAS 69 is as follows:
(4) LONG-TERM BANK DEBT: - --------------------------------------------------------------------------------
In December 1993, the Company entered into a secured master 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, which amount is subject to semi-annual redetermination, and up to $17,500,000 for working capital and general corporate purposes. 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. Borrowings under the Credit Facility bear interest at the Chase base rate plus 3/8 of 1% or 1,2,3 or 6 month LIBOR plus 1 and 5/8%, payable quarterly. A commitment fee of 1/2 of 1% is charged on unused availability. 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, 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, 1993 the outstanding balance under the credit facility was $25,000,000 at an interest rate of 6.375%. The Company did not meet the test imposed by the working capital covenant of the Credit Facility; compliance with this covenant was waived by Chase at December 31, 1993.
(5) NONRECOURSE SECURED LOAN AND PRODUCTION PAYMENT OBLIGATION: - --------------------------------------------------------------------------------
NONRECOURSE SECURED LOAN: On December 30, 1993, the Company entered into a nonrecourse secured loan agreement which bears annual interest at the rate of 12.5%, arranged by Enron Finance Corp., an affiliate of Enron Gas Services (the Enron loan). Approximately $51,600,000 was advanced on December 30, 1993 to provide financing for a portion of the West Cameron/Eugene Island and Loma Vieja 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 amount of $57,400,000 was recorded as a liability of $53,101,000 to reflect conveyance to the lender of a 20% interest in the net profits, as defined, of the Loma Vieja properties. The loan discount of $4,299,000 will be amortized over the life of the loan using the effective interest method.
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 1994 payments will reduce the recorded liability by approximately $983,000; this amount is included in current liabilities. Estimated liability reductions for 1995 through 1997,
(5) NONRECOURSE SECURED LOAN AND PRODUCTION PAYMENT OBLIGATION (cont'd): - ------------------------------------------------------------------------------- under the same production, pricing, capital expenditure and amortization scenario, are $12,385,000, $20,485,000, and $19,248,000, 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 MCF equivalent basis, are dedicated to repayment of the Enron loan.
PRODUCTION PAYMENT OBLIGATION: 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 of 15.5%. At December 31, 1993 the remaining recorded liability was $21,305,000. Under the terms of the dollar- denominated production payment agreement entered into in 1992 in connection with the Harbert acquisition, Forest I Development 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's current estimate, based on expected production and prices, budgeted capital expenditure levels and expected discount amortization, is that 1994 payments will reduce the recorded liability by approximately $3,388,000; this amount is included in current liabilities. Estimated liability reductions for 1995 through 1998, under the same production, pricing, capital expenditure and discount scenario, are $1,949,000, $3,522,000, $4,492,000 and $2,340,000, respectively. Properties to which approximately 7% of the Company's estimated proved reserves are attributable, on an equivalent barrel basis, are pledged under the production payment financing through July 1999.
(6) SENIOR SECURED NOTES AND SUBORDINATED DEBENTURES:
SENIOR SECURED NOTES: The Senior Secured Notes were issued in 1991 in connection with the Company's recapitalization and were redeemed in full during 1993. Amounts outstanding at December 31, 1992 were as follows (In Thousands):
Accretion of the original issue discount relating to the Senior Secured Notes was calculated using the effective interest method over the life of the issue.
The Senior Secured Notes bore interest at 12-3/4%, were due June 1, 1998, and were initially secured by liens on substantially all of the Company's oil and gas properties in the United States, including all reserves attributable thereto. The provisions of the Senior Secured Notes contained restrictions on dividends or cash distributions on or purchases of capital stock, prohibited payment of cash dividends on the Company's Common Stock and Class B Stock prior to January 1, 1994 and were subject to required purchase provisions upon occurrence of certain specified events.
Pursuant to the provisions of the Senior Secured Notes, the Company was required to make an offer to purchase Senior Secured Notes with 50% of the net cash proceeds (as defined) of the ONEOK litigation. (See Note 11). The amount of Senior Secured Notes tendered pursuant to such offer was $3,926,000. The purchase resulted in a loss of $614,000 which was recorded as a reduction of miscellaneous net revenue in 1992.
(6) SENIOR SECURED NOTES AND SUBORDINATED DEBENTURES (cont'd): - -------------------------------------------------------------------------------
The Senior Secured Notes were senior in right of payment to the 13-5/8% Debentures, 12-1/2% Debentures, 13-7/8% Debentures and 5-1/2% Debentures. The redemption of the Senior Secured Notes was completed using the net proceeds from a Common Stock offering and a portion of the proceeds from the sale of 11- 1/4% Senior Subordinated Notes described below. The outstanding principal value of the Senior Secured Notes of $61,847,000 at December 31, 1992 was redeemed during 1993, resulting in a loss of $9,419,000.
Subordinated Debentures: Subordinated debentures outstanding at December 31 were as follows:
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 Senior Subordinated Notes will be 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 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.
The 13-5/8% Debentures were due September 15, 1998. The outstanding balance of the 13-5/8% Debentures of $72,374,000 at December 31, 1992 was redeemed during 1993, resulting in a loss of $5,839,000.
The 12-1/2% Debentures were due May 1, 1999. The outstanding balance of the 12- 1/2% Debentures of $4,408,000 at December 31, 1992 was redeemed during 1993, resulting in a loss of $78,450.
(6) SENIOR SECURED NOTES AND SUBORDINATED DEBENTURES (CONT'D): - -------------------------------------------------------------------------------
The 13-7/8% Debentures were due June 1, 2000. The outstanding balance of the 13-7/8% Debentures of $4,914,000 at December 31, 1992 was redeemed during 1993, resulting in a loss of $53,000.
During 1993, the Company purchased $308,000 principal amount of its 5-1/2% Convertible Subordinated Debentures, resulting in a gain of $2,000. The remaining balance of $7,171,000 was paid in full on the February 1, 1994 due date.
In 1991, the Company consummated exchange offers pursuant to which the Company's outstanding debt was exchanged for Senior Secured Notes and warrants to purchase Common Stock. Holders of $62,010,000 principal amount of the Company's 12-1/2% Debentures, 13-7/8% Debentures and 13-5/8% Debentures accepted the Company's exchange offers, which were accounted for as extinguishments of debt. Therefore, the Company recognized an extraordinary gain on such transactions equal to the excess of the carrying amount of the debentures exchanged over the estimated market value of the Senior Secured Notes and Warrants issued. The gain on the transactions of $14,397,000, reduced by applicable income taxes of $4,895,000, was recorded as an extraordinary gain on extinguishment of debt in 1991.
(7) DEFERRED REVENUE: - --------------------------------------------------------------------------------
In April 1991, the Company sold a volumetric production payment from the Company's interest in four properties to Enron Reserve Acquisition Corporation (Enron) for net proceeds of $43,680,000. The production payment agreement covered approximately 30 BCF of natural gas to be delivered over six years at an average price of $1.38 per MMBTU. From November 1991 through February 1992, the Company acquired additional interests in one of the subject properties for $15,465,000 and sold a second volumetric production payment to Enron for net proceeds of $12,035,000. This second production payment covered approximately 9 BCF of natural gas to be delivered over four years at an average price of $1.26 per MMBTU. In connection with the purchase of TEPCO in July 1992, a volumetric production payment from certain of the TEPCO properties was sold to Enron for net proceeds of $38,522,000. This production payment covered approximately 18 BCF of natural gas at an average price of $1.39 per MMBTU and 770,000 barrels of oil at an average price of $15.99 per barrel to be delivered over four years. In connection with the purchase of interests in properties from ARCO in May 1993, a volumetric production payment from certain of the ARCO properties was sold to Enron for net proceeds of $27,260,000. This production payment covered approximately 13.1 BCF of natural gas at an average price of $1.92 per MMBTU to be delivered over three 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. The Company may grant liens on properties subject to this production payment agreement, but it must notify prospective lienholders that their rights are subject to the prior rights of the production payment owner.
In connection with the purchase of interests in properties from ARCO in December 1993, a volumetric production payment from certain of the ARCO proerties was sold to Enron for net proceeds of $13,207,000. This production payment covered approximately 7.3 BCF of natural gas at an average price of $1.68 per MMBTU to be delivered over 8 years.
The Company is responsible for royalties and for production costs associated with operating the properties subject to the production payment agreements.
(7) DEFERRED REVENUE (CONT'D): - --------------------------------------------------------------------------------
Amounts received were recorded as deferred revenue. Annual amortization of deferred revenue, based on the scheduled deliveries under the production payment agreements, is as follows:
The Company includes reserves dedicated to the volumetric production payments in its estimated proved oil and gas reserves. (See Note 19.)
(8) 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 is determined as of January 1, 1993 and is 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 benefit at December 31, 1993 on the loss from continuing operations was approximately $167,000 less than it would have been without such increase in the tax rate. However, due to limitations on the recognition of deferred tax assets under SFAS No. 109, the total tax benefit at December 31, 1993, including the tax benefit on the extraordinary loss on extinguishment of debt, is unaffected by the tax rate increase. The impact of the tax rate increase on the Company's total tax expense will be recognized when future taxable income absorbs the present unrecognized deferred tax asset.
(8) INCOME TAXES (CONT'D): - --------------------------------------------------------------------------------
Income taxes that are classified as deferred are generally the result of 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.
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, 1993 was $5,234,000. The net change in the total valuation allowance for the year ended December 31, 1993 was an increase of $2,034,000.
The Alternative Minimum Tax (AMT) credit carryforward available to reduce future Federal regular taxes aggregated $2,206,000 at December 31, 1993. This amount may be carried forward indefinitely. Regular and AMT net operating loss carryforwards at December 31, 1993 were $28,439,000 and $23,916,000, 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 $3,885,000 at December 31, 1993 and expire at various dates through the year 2001. Percentage depletion carryforwards available to reduce future Federal taxable income aggregated $20,174,000 at December 31, 1993. This amount may be carried forward indefinitely. The net operating loss and investment tax credit carryforwards have been recognized as a reduction of deferred taxes, subject to a valuation allowance.
(8) 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 Recapitalization. At December 31, 1993, 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 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, 1993, there is no significant limitation on the Company's ability to use these net operating loss carryforwards or investment tax credit carryforwards.
(9) PREFERRED STOCK: - -------------------------------------------------------------------------------
At December 31, 1993, there were 2,880,973 outstanding shares of $.75 Convertible Preferred Stock, par value $.01 per share. 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 1993, 248,817 shares of $.75 Convertible Preferred Stock were converted into 870,858 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 $10.50 per share during the twelve-month period which began July 1, 1993 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 has paid such dividends in shares of Common Stock. Thereafter, 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. Common Stock delivered in payment of dividends 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. If two consecutive dividend payments are in arrears, the holders of $.75 Convertible Preferred Stock may exercise a penalty conversion right during a specified period and may convert shares of $.75 Convertible Preferred Stock, plus accumulated dividends, to Common Stock at a conversion price of 75% of the average last reported sales price during a specified period prior to the conversion date. If six consecutive dividend payments are in arrears, the holders of the $.75 Convertible Preferred Stock shall have the right to elect two directors.
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.
In 1985, the Company issued 350,000 shares of $15.75 Cumulative Preferred Stock (Redeemable Preferred Stock), par value $.01 per share. In February 1990, the Company issued 2,300,000 shares of $2.125 Convertible Preferred
(9) PREFERRED STOCK (cont'd): - --------------------------------------------------------------------------------
Stock with a par value of $.01 per share and liquidation value of $25 per share. In December 1991, in connection with the Company's recapitalization, the Company's shareholders approved an amendment to the Company's Restated Certificate of Incorporation whereby each share of Redeemable Preferred Stock, including accumulated dividends, was acquired by the Company for seven shares of $.75 Convertible Preferred Stock or, at the election of the holder, for $50 principal amount of Senior Secured Notes and 1.2 shares of $.75 Convertible Preferred Stock and whereby each share of the Company's $2.125 Convertible Preferred Stock, including accumulated dividends, was reclassified into one share of $.75 Convertible Preferred Stock. In December 1991, also in connection with the recapitalization, the Company's shareholders approved an amendment to the Company's Restated Certificate of Incorporation whereby each share of the Company's $2.125 Convertible Preferred Stock, including accumulated dividends, was reclassified into one share of $.75 Convertible Preferred Stock.
(10) COMMON STOCK: - --------------------------------------------------------------------------------
At December 31, 1993 the Company has one class of Common Stock, par value $.10 per share, which 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. During 1992 the Company granted options to 42 employees to purchase a total of 1,740,000 shares of Common Stock at an exercise price of $3.00 per share. During 1993, the Company granted options to 33 employees to purchase a total of 1,525,000 shares of Common Stock at an exercise price of $5.00 per share. 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. At December 31, 1993, there are 1,529,000 options outstanding at an exercise price of $3.00 per share, of which 776,600 are exercisable, and 1,525,000 options outstanding at $5.00 per share, of which 525,000 are exercisable.
(11) 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.
(12) RESTRUCTURING: - --------------------------------------------------------------------------------
Restructuring expense in 1991 of approximately $3,585,000 related to reductions in workforce and a consolidation of the Company's technical staff, reduced by a credit recognized upon curtailment of the Company's defined benefit pension plan.
(13) EMPLOYEE BENEFITS: - --------------------------------------------------------------------------------
PENSION PLANS: The Company has a qualified defined benefit pension plan (Pension Plan). In 1991, in conjunction with its reorganization, the Company effected a curtailment of the Pension Plan pursuant to which all benefit accruals were suspended effective May 31, 1991. As a result of the curtailment, the projected benefit obligation was reduced significantly. Accordingly, the Company recorded a credit to restructuring expense of $806,000 in accordance with Statement of Financial Accounting Standards No. 88.
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. The Company's funding policy has been to contribute annually an amount in excess of the minimum required by Federal regulations. No contribution was made in 1993, 1992 or 1991. 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 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%. 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 both 1992 and 1991.
(13) EMPLOYEE BENEFITS (cont'd): - -------------------------------------------------------------------------------
In 1990, the Company adopted 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, 1993 the projected benefit obligation under this plan totaled $493,000, 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.
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.
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 1993, 1992 and 1991, Company contributions were made using treasury stock. The expense associated with the Company's contribution was $367,000 in 1993, $454,000 in 1992 and $492,000 in 1991.
Effective January 1, 1992 the plan was amended to include profit-sharing contributions by the Company. 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 whole shares of the Company's Common Stock, generally based in part upon the Company attaining certain levels of performance. 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,
(13) EMPLOYEE BENEFITS (cont'd): - -------------------------------------------------------------------------------
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 ($149,000) payable in May 1997. The retirement agreements for the other six Retirees, one of 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 an annual rate of 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 $861,000, $995,000, and $1,534,000 in 1993, 1992 and 1991, respectively, including $766,000, $765,000, and $1,335,000 paid for policies for retired executives. Under the split dollar life insurance plans, the Company was assigned a portion of the benefits payable under the policies which were generally designed to recover the premiums paid by the Company as well as any bonuses paid to the employees and retirees in connection with the policies. In December 1991 the Company replaced the existing policies with new, lower cost policies which provide the same death benefits to the employees and retirees. The Company is assigned a portion of the benefits which is designed to recover the premiums paid. As a result of the change in policies, the Company was able to receive 100% of the cash surrender value of the old policies, net of outstanding policy loans. The net cash surrender value of $4,422,000 was received in 1992.
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 and recognizes the expense in the year incurred. Effective January 1, 1992, the Company replaced its health and dental plans with new plans which require employees and eligible retirees to contribute an estimated 50% of the cost of dependent coverage. In 1993, 1992 and 1991 the costs of providing these benefits for both active and retired employees totalled $1,350,000, $1,359,000, and $2,111,000, respectively. The 1993 cost includes $993,110 related to 184 participating active employees and 4 employees on long- term disability and $356,890 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. The cost of providing these benefits during 1991 for the 164 eligible retirees are not separable from the costs of providing these benefits for the 182 participating active employees.
POSTRETIREMENT BENEFITS: In December 1990, the Financial Accounting Standards Board issued the Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," (SFAS No. 106). This statement required the Company to accrue expected costs of providing postretirement benefits to employees, their beneficiaries and covered dependents effective for fiscal years beginning after December 15, 1992. 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 $483,000 for 1993.
(13) EMPLOYEE BENEFITS (cont'd): - -------------------------------------------------------------------------------
At January 1 and December 31, 1993 the discount rates used in determining the actuarial present value of the accumulated postretirement benefit obligation were 8.5% and 7.5%, respectively.
POSTEMPLOYMENT BENEFITS: In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" (SFAS No. 112). This statement requires the accrual of the estimated cost of certain postemployment benefits provided to former employees. SFAS No. 112 is effective for years beginning after December 15, 1993. The initial effect of applying this statement is to be accounted for as a cumulative effect of a change in accounting principle. The Company has not determined precisely what effect, if any, the adoption of SFAS No. 112 will have on its financial statements, but believes the effect will be immaterial because the Company has already recorded liabilities for many of the affected costs.
(14) RELATED PARTY TRANSACTIONS: - -------------------------------------------------------------------------------
The Company uses 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. The Company incurred expenses for its use of the Complex of $635,000 in 1993, $611,000 in 1992, and $691,000 in 1991. The Company has notified the owners that it intends to terminate its annual usage after 1994, and it will pay $600,000 for its 1994 usage and $300,000 as a partial reimbursement of deferred maintenance costs.
John F. Dorn resigned as an executive officer and director of the Company in 1993. The Company has agreed to pay John F. Dorn his salary at time of resignation through September 30, 1996. In addition, the Company has provided certain other benefits and services to Mr. Dorn. The present value of the severance package is estimated at $500,000, which amount was recorded as an expense and a liability at December 31, 1993.
In March 1994, the Company sold certain non-strategic oil and gas properties for $4,400,000 to an entity controlled by John F. Dorn and another former executive officer of the Company. 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 is 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.
(15) COMMITMENTS AND CONTINGENCIES: - -------------------------------------------------------------------------------
Future rental payments for office facilities and equipment under the remaining terms of noncancelable leases are $2,210,000, $1,324,000 and $130,000 for the years ending December 31, 1994, 1995 and 1996, respectively.
Net rental payments applicable to exploration and development activities and capitalized in the oil and gas property accounts aggregated $688,000 in 1993, $874,000 in 1992 and $1,562,000 in 1991. Net rental payments charged to expense amounted to $3,098,000 in 1993, $3,112,000 in 1992 and $2,748,000 in 1991. 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 financial condition of the Company.
(16) FINANCIAL INSTRUMENTS: - -------------------------------------------------------------------------------
Statement of Financial Accounting Standards No. 105 requires certain disclosures about financial instruments with off-balance-sheet risk. 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. 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. The following table indicates outstanding energy swaps of the Company which were in place at December 31, 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 gives Forest the right to set a floor price of $1.70 per MMBTU on a total of 18.4 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 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.
In December 1991, the Financial Accounting Standards Board issued Statement 107, "Disclosures about Fair Value of Financial Instruments." The statement requires disclosure of the estimated fair value of certain on and off-balance sheet financial instruments in the financial statements. The following methods and assumptions were used to estimate the fair value of the Company's financial instruments as of December 31, 1993:
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLES AND ACCOUNTS PAYABLE: The carrying amount of these instruments approximates fair value because of their short maturity.
(16) FINANCIAL INSTRUMENTS (cont'd): - --------------------------------------------------------------------------------
PRODUCTION PAYMENT OBLIGATION: The fair value of the Company's production payment obligation has been estimated as approximately $20,433,000 by discounting the projected future cash payments required under the agreement by 12.5%. This rate corresponds to the rate on the Company's recent nonrecourse loan agreement.
SENIOR SUBORDINATED NOTES The fair value of the Company's 11 1/4% Subordinated Notes was approximately $112,179,000, 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 $508,000, based upon the estimated net amount the Company would receive to terminate the agreements.
(17) 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:
(19) 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 three years ended December 31, 1993:
(B) AGGREGATE CAPITALIZED COSTS - The aggregate capitalized costs relating to oil and gas activities were incurred as of the date indicated:
(19) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (unaudited) (cont'd) - --------------------------------------------------------------------------------
(C) RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES - Results of operations from producing activities for 1993, 1992 and 1991 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.
(19) 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 1991, 1992 and 1993 follows. Such estimates are inherently imprecise and may be subject to substantial revisions.
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 16), but not on escalations based on future conditions. The Company has decreased these quantities for overproduced volumes recognized as revenue, as discussed in Note 1. The reserve volumes include quantities subject to volumetric production payments discussed in Note 7.
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.
Purchases of reserves in place represent volumes recorded on the closing dates of the acquisitions for financial accounting purposes.
(19) 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.
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. At 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 and the volumetric production payments, as discussed in Notes 7 and 16, and have been reduced for overproduced volumes recognized as revenue, as discussed in Note 1.
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.
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 in the United States was $35,028,000 at December 31, 1993 and $32,718,000 at December 31, 1992.
(19) 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 decrease during each of the last three years of the total standardized measure of discounted future net cash flows is as follows:
PART III
For information concerning Item 10

Item 10 - Executive Officers of Registrant, see Part I - Item 4A.
PART IV
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, 1993 and 1992
3. Consolidated Statements of Operations - Years ended December 31, 1993, 1992 and 1991
4. Consolidated Statements of Shareholders' Equity - Years ended December 31, 1993, 1992 and 1991
5. Consolidated Statements of Cash Flows - Years ended December 31, 1993, 1992 and 1991
6. Notes to Consolidated Financial Statements - Years ended December 31, 1993, 1992 and 1991
(2) FINANCIAL STATEMENT SCHEDULES
1. Independent Auditors' Report
2. Schedule V: Property and Equipment - Years ended December 31, 1993, 1992 and 1991
3. Schedule VI: Accumulated Depreciation, Depletion and Valuation Allowance of Property and Equipment - Years ended December 31, 1993, 1992 and 1991
4. Schedule X: Supplementary Operating Statement Information - Years ended December 31, 1993, 1992 and 1991
Financial statement schedules omitted: All other 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.
*Exhibit 3(ii)(b) Amendment No. 8 to By-Laws dated as of February 24, 1994.
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.
*Exhibit 4.3 Amendment No. 1 dated as of December 28, 1993 relating to Exhibit 4.2 hereof.
*Exhibit 4.4 Amendment No. 2 dated as of January 27, 1994 relating to Exhibit 4.2 hereof.
*Exhibit 4.5 Security Agreement dated as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan Bank (National Association), as agent.
*Exhibit 4.6 Deed of Trust, Mortgage, Security Agreement, Assignment of Production, Financing Statement (Personal Property including Hydrocarbons), and Fixture Filing dated as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan Bank (National Association), as agent.
Exhibit 4.7 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 4.8 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 4.9 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 4.10 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 4.11 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 Form of non-qualified Deferred Compensation Agreement, incorporated herein by reference to Exhibit 10.3 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1990 (File No. 0-4597).
+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.
*+Exhibit 10.10 Form of Settlement Agreement and General Release between John F. Dorn and Forest Oil Corporation dated March 7, 1994.
*Exhibit 11 Forest Oil Corporation and Subsidiaries - Calculation of Earnings per Share of Common Stock.
*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 28 Form 11-K of the Thrift Plan of Forest Oil Corporation for the year ended December 31, 1993.
* 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
The following reports on Form 8-K were filed by Forest during the last quarter of 1993:
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: March 28, 1994 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 March 28, 1994 (William L. Dorn) Chief Executive Officer (Principal Executive Officer)
Robert S. Boswell* President and Chief Financial Officer March 28, 1994 (Robert S. Boswell) (Principal Financial Officer)
David H. Keyte* Vice President and Chief Accounting March 28, 1994 (David H. Keyte) 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 March 28, 1994
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 March 28, 1994
Jeffrey W. Miller* (Jeffrey W. Miller)
Jack D. Riggs* (Jack D. Riggs)
Michael B. Yanney* (Michael B. Yanney)
*By /s/ Daniel L. McNamara March 28, 1994 ----------------------------- Daniel L. McNamara (as attorney-in-fact for each of the persons indicated)
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders Forest Oil Corporation:
Under date of February 22, 1994, we reported on the consolidated balance sheets of Forest Oil Corporation and subsidaries as of December 31, 1993 and 1992, 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, 1993, as contained in the annual report on Form 10-K for the year 1993. In connection with our audits of the aforementioned consolidated financial statements, we have also audited the related financial statement schedules V, VI, and X. These financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statement schedules based on our audit.
In our opinion, the related financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Notes 8 and 13 to the financial statements, the Company changed its method of accounting for income taxes and postretirement benefits.
KPMG PEAT MARWICK
Denver, Colorado February 22, 1994
SCHEDULE V
FOREST OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES Property and Equipment Years ended December 31, 1993, 1992 and 1990 (In Thousands)
SCHEDULE VI
FOREST OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES Accumulated Depreciation, Depletion and Valuation Allowance of Property and Equipment Years ended December 31, 1993, 1992 and 1991 (In Thousands)
SCHEDULE X
FOREST OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES Supplementary Income Statement Information
Years ended December 31, 1993, 1992 and 1991
Other supplementary income statement information required by Rule 12-11 is not presented because the required item does not exceed 1 percent of total sales and revenues reported in the related income statement, except for maintenance and repair costs included in the Company's oil and gas production expense. Such maintenance and repair costs cannot be distinguished from other components of lease operating expense.