ITEM 1. BUSINESS
THE COMPANY
Forest Oil Corporation and its subsidiaries (Forest or the Company) are engaged in the acquisition, exploration, development, production and marketing of natural gas and crude oil in North America. 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 and in Canada.
Forest's principal reserves and producing properties are located in the Gulf of Mexico, Texas, Oklahoma and Alberta, Canada. Approximately 60% of total 1996 production was in the United States and approximately 40% was in Canada. The Company currently operates 45 offshore platforms in the Gulf of Mexico, and 1996 production from this area accounted for approximately 42% of the Company's reported production on an MCFE basis. (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 liquids to 6 MCF of natural gas. BCFE means billions of cubic feet of natural gas equivalents. With respect to liquids, the term BBL means one barrel of liquids whereas MBBLS is used to designate one thousand barrels of liquids. The term liquids is used to describe oil, condensate and natural gas liquids.)
The Company operates from production offices located in Lafayette, Louisiana; Denver, Colorado; and Calgary, Alberta. Forest's corporate headquarters are located in Denver, Colorado. On December 31, 1996 Forest had 243 employees, of whom 179 were salaried and 64 were hourly.
OPERATING STRATEGY
The Company's objective is to increase value through sustained profitable growth of its oil and gas reserves and production by pursuing a combined strategy of focused acquisitions, exploration and development, while reducing operating and financial risk. The Company intends to focus its activity onshore and offshore in the Gulf Coast of the U.S. and in the Western Sedimentary Basin both in the U.S. and in Canada. In recent years, the Company has grown primarily by acquiring reserves with exploitation potential, increasing production from existing fields and exploration of its undeveloped acreage.
On January 31, 1996 Forest acquired ATCOR Resources Ltd. for approximately $136,000,000, including acquisition costs of approximately $1,000,000. This company, which has been renamed Canadian Forest Oil Ltd. (Canadian Forest), is a Canadian corporation engaged in oil and gas exploration, production and processing in western Canada. Estimated proved reserves acquired in the Canadian Forest transaction were approximately 151 BCFE at an average property acquisition cost of $.85 per MCFE ($.60 per MCFE net of related deferred taxes). As part of the ATCOR acquisition, Forest separated ATCOR's natural gas marketing operation from its exploration and production business and renamed the marketing business Producers Marketing Ltd. (ProMark). In addition to marketing Canadian Forest's own gas production, ProMark provides a full range of gas marketing and management services to outside parties.
Other acquisitions by the Company during 1996 totaled 33 BCFE at an average property acquisition cost of $.69 per MCFE.
During 1995, the Company's acquisitions totaled 44.0 BCFE at an average property acquisition cost of $.61 per MCFE. These amounts represent primarily the reserves of Saxon Petroleum Inc. (Saxon), a consolidated
subsidiary of the Company in which the Company purchased a majority interest on December 20, 1995. Saxon is an Alberta, Canada corporation engaged in oil and gas exploration and production primarily in western Canada.
The Company had estimated proved reserves of 481 BCFE at December 31, 1996 of which approximately 70% were natural gas reserves. This represents an increase of 60% compared to estimated proved reserves of 301 BCFE at December 31, 1995 of which approximately 79% was natural gas.
Forest has dedicated an increased percentage of its capital expenditure budget to exploration activities in 1997. The Company participates in exploration activities through selective drilling for its own account, as well as through farmout arrangements in certain circumstances. Forest was successful at both 1996 federal offshore sales and at the March 1997 sale. The Company acquired one block at the central (Louisiana) sale in April 1996 and five blocks at the western (Texas) sale in September 1996. The Company was high bidder on eight blocks at the March 1997 central sale, although the leases have not been formally awarded as of March 20, 1997. Forest has also re-established its exploration effort in the Western Sedimentary Basin of the U.S. and Canada.
Throughout the remainder of 1997, the Company also intends to continue to pursue its strategy of acquiring additional reserves that satisfy its investment criteria and are within the limits of its capital constraints. Forest continues to evaluate potential acquisitions, as well as various types of business combinations and joint ventures.
The Company's operating strategy also includes exploitation activities in the areas of reservoir management and development drilling. Reservoir management involves the effort to enhance value by a combination of reduced costs and the use of techniques such 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.
As a part of its operating strategy, the Company also conducts an ongoing disposition program of its non-strategic assets. Assets with little value or which are not consistent with the Company's ongoing operating strategy are identified for sale or trade. During 1996, the Company disposed of properties with estimated proved reserves of approximately 1.5 BCF of natural gas and 628,000 barrels of oil for total net proceeds of $6,916,000. In addition, Saxon received proceeds of approximately $10,959,000 representing the liquidation of its preferred shares in Archean Energy Ltd. These shares, which were received through a series of transactions relating to the 1992 sale of the Company's Canadian oil and gas properties, were transferred to Saxon by Forest in 1995.
Prior to 1996, the Company was not able to exploit the full potential of its acquisitions due to financial constraints resulting from its highly leveraged capital structure and low natural gas prices. During 1995, the Company sold equity securities to The Anschutz Corporation (Anschutz) for $45,000,000 and restructured $62,400,000 of indebtedness to Joint Energy Development Investments Limited Partnership (JEDI), a Delaware limited partnership the general partner of which is an affiliate of Enron Corp. (Enron). In December 1995, the Company agreed to exchange 1,680,000 shares of common stock for $22,400,000 of JEDI indebtedness and warrants to acquire Forest common stock. In January 1996, the Company completed the purchase of Canadian Forest using the proceeds of a common stock offering and approximately $8,300,000 of borrowings under its bank credit facility. Forest also established a $60,000,000 CDN credit facility secured by the oil and gas properties of Canadian Forest. As a result of these transactions, the Company has improved its financial flexibility significantly. The Company believes such improved financial flexibility should allow Forest to exploit its expanded property base more effectively. During the remainder of 1997, the Company intends to expand its exploration effort as well as pursue its acquisition and exploitation strategy. For further information concerning the Company's acquisitions and operations, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and Notes thereto.
SALES AND MARKETS
Forest's U.S. production is generally sold at the wellhead to oil and natural gas purchasing companies in the areas where it is produced. Crude oil and condensate are typically sold at prices which are based upon posted field prices. Natural gas in the U.S. is generally sold month to month on the spot market. For the month of March 1997, approximately 94% of the Company's U.S. natural gas was sold at the wellhead at spot market prices. The term "spot market" as used herein refers to contracts with a term of six months or less or contracts which call for a redetermination of sales prices every six months or earlier. The remainder of the Company's U.S. natural gas was committed to both interstate and intrastate natural gas pipeline companies, primarily under volumetric production payment agreements and long-term contracts. The Company believes that the loss of one or more of its current natural gas spot purchasers should not have a material adverse effect on the Company's business in the United States because any individual spot purchaser could be readily replaced by another spot purchaser who would pay approximately the same sales price.
In Canada, Canadian Forest's natural gas production is sold primarily through the ProMark Netback Pool. The Netback Pool matches major end users with providers of gas supply through arranged transportation channels and uses a netback pricing mechanism to establish the wellhead price paid to producers. Under this netback arrangement, producers receive the blended market price less related transportation and other direct costs. ProMark charges a marketing fee for marketing and administering the gas supply pool.
Canadian Forest sold approximately 81% of its natural gas production through the Netback Pool in 1996.
The Netback Pool gas sales in 1996 averaged 125 MMCF per day, of which Canadian Forest supplied approximately 35 MMCF per day or 28%. Approximately 12% of the volumes sold in the Netback Pool in 1996 were sold at fixed prices under long-term contracts. The loss of one or more of such long-term buyers could have a material adverse effect on ProMark and Canadian Forest.
In addition to operating the Netback Pool, ProMark provides two other marketing services for producers and purchasers of natural gas. ProMark manages long-term gas supply contracts for its industrial customers by providing full-service purchasing, accounting and gas nomination services for these customers on a fee-for-services basis. ProMark also buys and sells gas in its trading operation for terms as short as one day and as long as one to two years. Profits generated by trading are derived from the spread between the prices of gas purchased and sold. ProMark endeavors to offset its gas purchase or sales commitments with other gas purchase or sales contracts, thereby limiting its exposure to price risk. The Company is, however, exposed to credit risk in that there exists the possibility that the counterparties to agreements will fail to perform their contractual obligations.
Substantially all of Forest's oil production in the U.S. and Canada is sold under short-term contracts at prices which are based upon posted field prices.
For information concerning sales to major customers, see Note 14 of Notes to Consolidated Financial Statements.
OTHER FOREIGN OPERATIONS
Forest considers, from time to time, certain oil and gas opportunities in other foreign countries. Foreign oil and natural gas operations are subject to certain risks, such as nationalization, confiscation, terrorism, renegotiation of existing contracts and currency fluctuations. Forest monitors the political, regulatory and economic developments in any foreign countries in which it operates.
COMPETITION
The oil and natural gas industry is intensely competitive. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Forest's competitive position depends on its geological, geophysical and engineering expertise, on its financial resources, its ability to develop its properties and its ability to select, acquire and develop proved reserves. Forest competes with a substantial number of other companies having larger technical staffs and greater financial and operational resources. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, generate electricity and market refined products. The Company also competes with major and independent oil and gas companies in the marketing and sale of oil and gas to transporters, distributors and end users. There is also competition between the oil and natural gas industry and other industries supplying energy and fuel to industrial, commercial and individual consumers. Forest also competes with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time. Finally, companies not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Such companies will also provide competition for Forest.
Forest's business is affected not only by such competition, but also by general economic developments, governmental regulations and other factors that affect its ability to market its oil and natural gas production. The prices of oil and natural gas realized by Forest are highly volatile. The price of oil is generally dependent on world supply and demand, while the price Forest receives for its natural gas is tied to the specific markets in which such gas is sold. Declines in crude oil prices or natural gas prices adversely impact Forest's activities. The Company's financial position and resources may also adversely affect the Company's competitive position. Lack of available funds or financing alternatives will prevent the Company from executing its operating strategy and from deriving the expected benefits therefrom. For further information concerning the Company's financial position, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
ProMark also faces significant competition from other gas marketers, some of whom are significantly larger in size and have greater financial resources than ProMark, Canadian Forest or the Company.
REGULATION
UNITED STATES. Various aspects of the Company's oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted and by certain agencies of the Federal government for operations on Federal leases. The Federal Energy Regulatory Commission (FERC) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). In the past, the Federal government has regulated the prices at which oil and gas could be sold. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the Decontrol Act). The Decontrol Act removed all NGA and NGPA price and nonprice controls affecting wellhead sales of natural gas effective January 1, 1993.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C (Order No. 636), which require interstate pipelines to provide transportation separate, or "unbundled", from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Although Order No. 636 does not directly regulate the Company's activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company's activities. Although Order No. 636, assuming it is upheld in its entirety, could provide the Company with additional market access and more fairly applied transportation service rates, Order No. 636 could also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of
those tolerances. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have been the subject of appeals, the results of which have generally supported the FERC's open-access policy. Last year, the United States Court of Appeals for the District of Columbia Circuit largely upheld Order No. 636. Because further review of certain of these orders is still possible and other appeals remain pending, it is difficult to predict the ultimate impact of the orders on the Company and its production efforts.
The FERC has announced several important transportation-related policy statements and proposed rule changes, including the appropriate manner in which interstate pipelines release capacity under Order No. 636 and, more recently, the price which shippers can charge for their released capacity. In addition, in 1995, FERC issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. In January 1996, the FERC issued a policy statement and a request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While any additional FERC action on these matters would affect the Company only indirectly, these policy statements and proposed rule changes are intended to further enhance competition in natural gas markets. The Company cannot predict what action the FERC will take on these matters, nor can it predict whether the FERC's actions will achieve its stated goal of increasing competition in natural gas markets. However, the Company does not believe that it will be treated materially differently than other natural gas producers and markets with which it competes.
Commencing in October 1993, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling levels. The indexing system, which allows or may require pipelines to make rate changes to track changes in the Producer Price Index for Finished Goods, minus one percent, became effective January 1, 1995 The Company is not able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on the transportation costs associated with oil production from the Company's oil producing operations.
The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines operating on or across the Outer Continental Shelf (the OCS) provide open-access, non-discriminatory service. Although the FERC has opted not to impose the regulations of Order No. 509, in which the FERC implemented the OCSLA, on gatherers and other non-jurisdictional entities, the FERC has retained the authority to exercise jurisdiction over those entities if necessary to permit non-discriminatory access to service or the OCS.
Certain operations the Company conducts are on federal oil and gas leases, which the Minerals Management Service (MMS) administers. The MMS issues such leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the OCSLA (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines. These proposed regulations were withdrawn pending further discussions among interested federal agencies. The MMS also has regulations restricting the flaring or venting of natural gas and has recently proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that the Company can continue to obtain bonds or other surety in all cases. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations.
In addition, the MMS is conducting an inquiry into certain contract agreements from which producers on MMS leases have received settlement proceeds that are royalty bearing and the extent to which producers have paid the appropriate royalties on those proceeds. The Company believes that this inquiry will not have a material impact on its financial condition, liquidity or results of operations.
The MMS has issued a notice of proposed rulemaking in which it proposes to amend its regulations governing the calculation of royalties and the valuation of natural gas produced from federal leases. The principal feature in the amendments, as proposed, would establish an alternative market-index based method to calculate royalties on certain natural gas production sold to affiliates or pursuant to non-arm's-length sales contracts. The MMS has proposed this rulemaking to facilitate royalty valuation in light of changes in the gas marketing environment. The Company cannot predict what action the MMS will take on these matters, nor can it predict at this stage of the rulemaking proceeding how the Company might be affected by amendments to the regulations.
The MMS has also issued a notice of proposed rulemaking in which it proposes to amend its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. This proposed rule would modify the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that better reflects market value, establish a new MMS form for collecting value differential data, and amend the valuation procedure for the sale of federal royalty oil. The Company cannot predict what action the MMS will take on this matter, nor can it predict at this stage of the rulemaking proceeding how the Company might be affected by this amendment to the MMS' regulations.
Additional proposals and proceedings that might affect the oil and gas industry are pending before the FERC and the courts. The Company cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by the FERC will continue indefinitely. Notwithstanding the foregoing, the Company does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of the Company or its subsidiaries. No material portion of Forest's business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the Federal government.
OIL SPILL FINANCIAL RESPONSIBILITY REQUIREMENTS - UNITED STATES. As originally enacted, the Oil Pollution Act of 1990 ("OPA") would have required the Company to establish $150 million in financial responsibility to cover oil spill related liabilities. Under recent amendments to the OPA, the responsible person for an offshore facility located seaward of state waters, including OCS facilities, will be required to provide evidence of financial responsibility in the amount of $35 million. Although the financial responsibility requirement for offshore facilities located landward of the seaward boundary of state waters (including certain facilities in coastal inland waters) is a lesser amount ($10 million), the Company currently has a number of offshore facilities located beyond state waters and, thus, is subject to the $35 million financial responsibility requirement. The amount of financial responsibility may be increased, to a maximum of $150 million, if the MMS determines that a greater amount is justified based on specific risks posed by the operations. The Company expects that financial responsibility could be established through insurance, guaranty, indemnity, surety bond, letter of credit, qualification as a self insurer or a combination thereof. The Company cannot predict the final form of any financial responsibility rule that may be adopted by the MMS under OPA, but in any event, the impact of the rule is not expected to be any more burdensome to the Company than it will be to other similarly situated companies involved in oil and gas exploration and production. The Company currently satisfies similar requirements for its OCS leases under OCSLA.
CANADA. The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect the operations of the Company in a manner materially different than they would affect other oil and gas companies of similar size.
In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends in part on oil quality, prices of competing fuels, distance to market and the value of refined products. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board (NEB). Any oil export to be made pursuant to a contract of longer duration requires an exporter to obtain an export license from the NEB and the issue of such a license requires the approval of the Canadian federal government.
In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the Government of Canada through the NEB. Producers and exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the NEB. As is the case with oil, natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Canadian federal government approval.
The provincial governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.
On January 1, 1994 the North American Free Trade Agreement (NAFTA) among the governments of Canada, the United States and Mexico became effective. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use, (ii) impose an export price higher than the domestic price, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements. NAFTA contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.
In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.
From time to time the governments of Canada, Alberta, British Columbia and Saskatchewan have established incentive programs which have included royalty rate deductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects.
In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC (Alberta royalty tax credit) program. The ARTC program is based on a price sensitive formula, and the ARTC rate varies between 75%, at prices for oil below $100 per cubic meter, and 25%, at prices above $210 per cubic meter. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average "par price", as determined by the Alberta Department of Energy for the previous quarterly period. Canadian Forest is eligible for ARTC credits only on eligible properties acquired and wells drilled after the change of control.
Oil and natural gas royalty holidays and reductions for specific wells reduce the amount of Crown royalties paid by the Company to the provincial governments. The ARTC program provides a rebate on Crown royalties paid in respect of eligible producing properties.
ENVIRONMENTAL MATTERS. Extensive federal, state, provincial and local laws govern oil and natural gas operations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect the operations of the Company. Compliance with environmental requirements generally could have a material adverse effect upon the capital expenditures, earnings or competitive position of Forest and its subsidiaries. The Company believes that it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. Nevertheless, changes in environmental law have the potential to adversely affect the Company's operations. For instance, at least two separate courts have recently ruled that certain wastes associated with the production of crude oil may be classified as hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund) and thus the Company could become subject to the burdensome cleanup and liability standards established under the federal Superfund program if significant concentrations of such wastes were determined to be present at the Company's properties or to have been produced as a result of the Company's operations. Alternately, pending amendments to Superfund presently under consideration by the U.S. Congress could relax many of the burdensome cleanup and liability standards established under the Statute.
In Canada, the oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties.
Environmental legislation in Alberta has undergone a major revision and has been consolidated into the ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT. Under the new Act, environmental standards and compliance for releases, clean-up and reporting are stricter. Also, the range of enforcement actions available and the severity of penalties have been significantly increased. These changes will have an incremental effect on the cost of conducting operations in Alberta.
Although the Company maintains insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on the Company's financial condition and operations.
The Company has established guidelines to be followed to comply with environmental laws, rules and regulations. The Company has designated a compliance officer whose responsibility is to monitor regulatory requirements and their impacts on the Company and to implement appropriate compliance procedures. The Company also employs an environmental manager whose responsibilities include causing Forest's operations to be carried out in accordance with applicable environmental guidelines and implementing adequate safety precautions. Although the
Company maintains pollution insurance against the costs of clean-up operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
Certain of the statements set forth under "Item 1. - Business" and "Item 7 - -Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Form 10-K, such as the statements regarding planned capital expenditures and the availability of capital resources to fund capital expenditures are forward-looking and are based upon the Company's current belief as to the outcome and timing of such future events. There are numerous risks and uncertainties that can affect the outcome and timing of such events, including many factors beyond the control of the Company. These factors include, but are not limited to, the matters described below. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Company's actual results and plans for 1997 and beyond could differ materially from those expressed in the forward-looking statements.
Many of the factors which may affect the Company's future operating performance and long-term liquidity are beyond the Company's control, including, but not limited to, oil and natural gas prices, governmental actions and taxes, the availability and attractiveness of properties for acquisition, the adequacy and attractiveness of financing and operational results. The Company is subject to the following risk factors.
AVAILABILITY OF FINANCING. The Company has historically addressed its long-term liquidity needs through the issuance of debt and equity securities, when market conditions permit, and through the use of nonrecourse production-based financing. The Company continues to examine alternative sources of long-term capital, including bank borrowings or the issuance of debt instruments, the sale of common stock, preferred stock or other equity securities of the Company, the issuance of net profits interests, sales of non-strategic properties, prospects and technical information, or joint venture financing. Availability of these sources of capital and, therefore, the Company's ability to execute its operating strategy will depend upon a number of factors, some of which are beyond the control of the Company.
REPLACEMENT OF RESERVES. In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics and vary from the steep declines characteristic of Gulf of Mexico reservoirs, where the Company has a significant portion of its production, to the relatively slow declines characteristic of long-lived fields in other regions. Except to the extent the Company acquires properties containing proved reserves or conducts successful development and exploration activities, or both, the proved reserves of the Company will decline as reserves are produced. The Company's future natural gas and oil production is, therefore, highly dependent upon its level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital investment to maintain or expand its asset base of oil and gas reserves would be impaired. In addition, there can be no assurance that the Company's future development, acquisition and exploration activities will result in additional proved reserves or that the Company will be able to drill productive wells at acceptable costs.
VOLATILITY OF NATURAL GAS PRICES. The Company's revenues, profitability and future rate of growth, if any, are substantially dependent upon prevailing prices for oil and natural gas and the ability of the Company to discover or acquire proved reserves. Historically, the prices for oil and natural gas have been quite volatile. The Company anticipates that such markets will continue to be volatile over the next year. The Company is impacted more by natural gas prices than by oil prices, because the majority of its production is natural gas. At December 31, 1996 70% of the Company's estimated proved reserves consisted of natural gas on an Mcfe basis. During 1996, 72% of the Company's total production consisted of natural gas. The volatility of the spot market for natural gas is due to factors beyond the Company's control, including seasonality of demand which may cause the price received for spot market natural gas to vary significantly between seasonal periods. Prices are also affected by actions of state and local agencies, the United States and foreign governments, and international cartels, all of
which are beyond the Company's control. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas. Any substantial or extended decline in the price of oil or natural gas would have a material adverse effect on the Company's financial condition and results of operations.
In order to attempt to minimize the product price volatility to which the Company is subject, the Company, from time to time, enters into energy swap agreements and other financial arrangements with third parties to attempt to reduce the Company's short-term exposure to fluctuations in future oil and natural gas prices. Long-term contracts entered into by the Netback Pool and the volumetric production payment agreements that the Company has entered into further minimize the price volatility to which the Company is subject. For further information concerning market conditions, long-term contracts, production payments and energy swap agreements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 5, 6, 12 and 13 of Notes to Consolidated Financial Statements.
CEILING LIMITATION WRITEDOWNS. The Company reports its operations using the full cost method of accounting for oil and gas properties. The Company capitalizes the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, the Company is subject to a ceiling limitation writedown to the extent of such excess. A ceiling limitation writedown is a charge to earnings which does not impact cash flow from operating activities. However, such writedowns impact the amount of the Company's shareholders' equity. The risk that the Company will be required to write down the carrying value of its oil and gas properties increases when oil and gas prices are depressed or volatile. In addition, writedowns may occur if the Company has substantial downward revisions in its estimated proved reserves or if purchasers or governmental action cause an abrogation of, or the Company voluntarily cancels, long-term contracts for its natural gas. Although the Company did not have a writedown in 1996 or 1995, the Company had a writedown of $58,000,000 in 1994. No assurance can be given that the Company will not experience additional writedowns in the future. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 18 of Notes to Consolidated Financial Statements.
GAS MARKETING. The Company's operations include gas marketing as a result of the Canadian Forest acquisition. ProMark's gas marketing operations consist of the marketing of its own gas production, the purchase and direct sale of third parties' natural gas, the handling of transportation and operations of such third party gas and spot purchasing and selling of natural gas. The profitability of such natural gas marketing operations depends in large part on the ability of the Company to assess and respond to changing market conditions, including credit risk. Profitability of such natural gas marketing operations also depends in large part on the ability of the Company to maximize the volume of third party natural gas which the Company purchases and resells and on the ability of the Company to obtain a satisfactory margin between the purchase price and the sales price for such volumes. The inability of the Company to respond appropriately to changing conditions in the gas marketing business could materially adversely affect the Company's results of operations.
GAS PROCESSING. As a result of the Canadian Forest acquisition, the Company's operations include processing of natural gas to extract various natural gas liquids. Canadian Forest's gas processing operations primarily consist of an interest in an ethane extraction plant located near Edmonton, Alberta. In order to obtain from natural gas suppliers volumes of committed natural gas reserves to maintain natural gas throughput at optimal levels, the plant must periodically contract to process additional natural gas volumes provided from new or existing sources. There can be no assurance that the Company will be successful in contracting additional natural gas to maintain optimal levels of throughput.
CREDIT RISK. ProMark buys and sells gas in its trading operation for terms as short as one day and as long as one to two years. Profits generated by trading are derived from the spread between the prices of gas purchased and sold. ProMark endeavors to offset its gas purchase or sales commitments with other gas purchase or sales contracts, thereby limiting its exposure to price risk.
The Company is, however, exposed to credit risk in that there exists the possibility that the counterparties to agreements will fail to perform their contractual obligations.
CURRENCY RISK. Following the acquisition of Canadian Forest in January 1996, a substantial portion of the Company's operations is located in Canada. The expenses of such operations are payable in Canadian dollars and most of the revenue derived from natural gas and oil sales is based upon U.S. dollar prices. The results of such Canadian operations will therefore be subject to the risks of fluctuation in the relative values of Canadian and U.S. dollars.
GENERAL RISKS OF OIL AND GAS OPERATIONS. The nature of the oil and gas business involves a variety of risks, including, but not limited to, the risks of operating hazards such as fires, explosions, cratering, blow-outs, adverse weather conditions, pollution, environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, encountering formations with abnormal pressures and, in horizontal wellbores, the increased risk of mechanical failure and collapsed holes, the occurrence of any of which could result in substantial losses to the Company. The Company conducts a substantial portion of its operations offshore in the Gulf of Mexico. Such operations are subject to certain risks including, but not limited to, capsizing, collision, sinking and grounding of rigs and vessels and adverse weather and sea conditions. These risks could result in substantial losses to the Company due to personal injury or loss of life, severe damage or destruction of property and equipment, pollution or other environmental damage clean-up costs, regulatory investigation and penalties and the suspension of operations. The Company maintains insurance against some, but not all, of these risks in amounts that management believes to be reasonable and in accordance with customary oil and gas industry practices. The occurrence of a significant event, however, that is not fully insured could have a material adverse effect on the Company's financial condition and results of operations.
COMPETITION. The Company operates in a highly competitive environment. The Company competes with major and independent oil and gas companies for the acquisition of desirable oil and gas properties, as well as the equipment and labor required to develop and operate such properties. The Company also competes with major and independent oil and gas companies in the marketing and sale of oil and natural gas to marketers and end-users. Many of these competitors have financial and other resources substantially greater than those of the Company.
DRILLING RISKS. Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling and completing wells is often unpredictable, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in delivery of equipment. There can be no assurance as to the success of the Company's future drilling activities. The Company's current inventory of 2-D and 3-D seismic surveys will not necessarily increase the likelihood that the Company will drill or complete commercially productive wells or that the volumes of reserves discounted, if any, would necessarily be greater than the Company would have discovered without its current inventory of seismic surveys.
ACQUISITION RISKS. The Company's growth has been attributable in part to acquisitions of producing properties. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors beyond the Company's control. Such assessments are necessarily inexact and their accuracy inherently uncertain. In connection with such an assessment, the Company performs a review of the subject properties that it believes to be generally consistent with industry practices. Such a review, however, will not reveal all existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. The Company is generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities, and generally acquires interests in the properties on an "as is" basis with limited remedies for breaches of representations and warranties.
MARKETABILITY OF OIL AND GAS PRODUCTION. The marketability of the Company's production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. U.S. federal and state regulation and Canadian regulation of oil and gas production and transportation, general economic conditions, and changes in supply and demand all could adversely affect the Company's ability to produce and market its oil and natural gas. If market factors were to change dramatically, the financial impact on the Company could be substantial. The availability of markets is beyond the control of the Company and thus represents a significant risk.
SEASONALITY OF DEMAND FOR NATURAL GAS. Demand for natural gas is highly seasonal, with demand generally higher in the colder winter months and in hot summer months. To date, the Company generally has been able to sell all of its available spot market natural gas at prevailing spot market prices; thus, the volumes sold by the Company have not fluctuated materially with seasonality. There is no assurance, however, that the Company will be able to continue to achieve this result.
GOVERNMENT REGULATION, ENVIRONMENTAL RISKS AND TAXES. Various aspects of the Company's oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states and provinces where such operations are conducted, by certain agencies of the Federal government for operations on Federal leases and by the Canadian government. In the past, the Federal government has regulated the prices at which oil and natural gas could be sold. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Extensive U.S., state and local laws and Canadian laws govern oil and gas operations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. These laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect the operations of the Company. Compliance with environmental requirements generally could have a material adverse effect upon the capital expenditures, earnings or competitive position of Forest. Although Forest's experience has been to the contrary, there is no assurance that this will continue to be the case.
ITEM 2.
ITEM 2. PROPERTIES
Forest's principal reserves and producing properties are oil and gas properties located in the Gulf of Mexico, Texas, Oklahoma and Alberta, Canada.
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 18 of Notes to Consolidated Financial Statements.
Since January 1, 1996 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 solely to Forest's Gulf of Mexico reserves. 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" dates of such reserve estimates.
PRODUCTION
The following table shows net liquids and natural gas production for Forest and its subsidiaries for the years ended December 31, 1996, 1995 and 1994:
Net Natural Gas and Liquids Production (1)(2) --------------------------------------------- 1996 1995 (3) 1994 ---- ---- ---- United States: Natural Gas (MMCF) 28,624 33,342 48,048 Liquids (MBBLS) 1,104 1,173 1,543
Canada: Natural Gas (MMCF) 13,872 - - Liquids (MBBLS) 1,645 - -
(1) Includes amounts delivered pursuant to volumetric production payments. See Note 6 of Notes to Consolidated Financial Statements. (2) Volumes reported for natural gas include immaterial amounts of sulfur production on the basis that one long ton of sulfur is equivalent to 15 MCF of natural gas. Liquids volumes include both oil and condensate and natural gas liquids. (3) Does not include any production relating to the acquisition of Saxon on December 20, 1995 as the amounts involved were not significant.
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 liquids and the average production cost per equivalent unit of production for the years ended December 31, 1996, 1995 and 1994 for Forest and its subsidiaries:
United States Canada (5) --------------------------- ---------- 1996 1995 1994 1996 ------- ------ ------ ------- Average Sales Prices: NATURAL GAS Total production (MMCF)(1) 28,624 33,342 48,048 13,872 Sales price received (per MCF)(2) $ 2.36 1.65 1.86 1.41 Effects of energy swaps (per MCF) (3) (.23) .12 .04 (.04) ------ ------ ------ ------
Average sales price (per MCF)(2) $ 2.13 1.77 1.90 1.37
LIQUIDS: Oil and Condensate: Total production (MBBLS)(4) 964 1,121 1,482 1,308 Sales price received (per BBL) $ 20.03 16.36 14.97 20.64 Effects of energy swaps (per BBL)(3) (1.07) (.50) (.14) (1.82) ------ ------ ------ ------
Average sales price (per BBL) $ 18.96 15.86 14.83 18.82
Natural gas liquids: Total production (MBBLS) 140 52 61 337 Average sales price (per BBL) $ 10.48 15.81 14.79 11.87
Total liquids production (MBBLS) 1,104 1,173 1,543 1,645 Average sales price (per BBL) $ 17.88 15.86 14.83 17.40
Average production cost (per MCFE)(6) $ .56 .56 .39 .52
(1) Total natural gas production includes scheduled deliveries under volumetric production payments, net of royalties, of 3,168 MMCF, 9,120 MMCF, and 16,005 MMCF in 1996, 1995 and 1994, respectively. Natural gas delivered pursuant to volumetric production payment agreements represented approximately 7%, 27% and 33% of total natural gas production in 1996, 1995 and 1994, respectively. For further information concerning volumes and prices recorded under volumetric production payments, see Notes 6 and 14 of Notes to Consolidated Financial Statements. (2) Amounts shown for 1995 exclude the effects of a gas contract settlement. Including such amount, the sales price received and average sales price for natural gas in 1995 were $1.78 and $1.90 per MCF, respectively. For further information regarding the gas contract settlement, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 15 of Notes to Consolidated Financial Statements. (3) Energy swaps were entered into to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 12,741 MMCF, 10,146 MMCF and 12,184 MMCF for the years ended December 31, 1996, 1995 and 1994, respectively. Hedged oil and condensate volumes were 895,600 barrels, 498,000 barrels and 370,000 barrels for 1996, 1995 and 1994, respectively. The aggregate gains (losses) under energy swap agreements were $(10,422,000), $3,536,000 and $1,810,000, respectively, for the years ended December 31, 1996, 1995 and 1994. (4) An immaterial amount of oil production is covered by scheduled deliveries under volumetric production payments.
(5) Alberta's royalty program was restructured in 1994 and remained uncertain throughout much of 1995 and 1996. Canadian production of natural gas liquids for the year ended December 31, 1996 was reduced by 79,000 barrels as a result of royalty adjustments, resulting in an increase in the reported average sales price for natural gas liquids in Canada to $11.87 per barrel from $9.44 or by approximately 26%. The royalty adjustments did not have a significant effect on reported volumes or average sales prices for natural gas or oil and condensate. Canadian Forest continues to receive additional information with respect to royalty calculations and anticipates that revisions to such calculations will continue to occur throughout 1997. The effects of future royalty adjustments cannot be predicted at this time. (6) Production costs were converted to common units of measure using a conversion ratio of one barrel of oil to six MCF of natural gas and one long ton of sulfur to 15 MCF of natural gas. Such production costs exclude all depreciation, depletion and provision for impairment associated with property and equipment.
PRODUCTIVE WELLS
The following summarizes total gross and net productive wells of the Company and its subsidiaries at December 31, 1996:
Productive Wells (1) ------------------------ United States Canada ------------- ------
Gross (2) Gas 278 379 Oil 180 566 ----- ----- Totals (3) 458 945 ----- ----- ----- -----
Net (4) Gas 100.7 127.0 Oil 118.5 225.9 ----- ----- Totals 219.2 352.9 ----- ----- ----- -----
(1) Productive wells are producing wells and wells capable of production, including wells that are shut-in. (2) A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. (3) Includes 27 dual completions in the United States and 20 dual completions in Canada. Dual completions are counted as one well. If one completion is an oil completion, the well is classified as an oil well. (4) A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
DEVELOPED AND UNDEVELOPED ACREAGE
Forest and its subsidiaries held acreage as set forth below at December 31, 1996 and 1995. A majority of the developed acreage is subject to mortgage liens securing either the bank indebtedness or nonrecourse secured debt of the Company and its subsidiaries. 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 5 and 6 of Notes to Consolidated Financial Statements.
Developed Acreage (1) Undeveloped Acreage (2) --------------------- ----------------------- Gross (3) Net (4) Gross (3) Net (4) --------- ------- --------- ------- United States: Louisiana offshore 145,549 58,662 53,212 20,774 Oklahoma 63,334 21,710 7,504 1,396 Texas onshore 123,959 61,529 15,813 8,394 Texas offshore 45,382 22,694 40,347 31,694 Wyoming 8,517 4,484 51,076 21,343 Other 26,304 10,959 6,114 1,773 ------- ------- ------- ------- 413,045 180,038 174,066 85,374
Canada Alberta 323,451 111,907 234,625 123,480 Other 61,301 41,191 283,124 43,731 ------- ------- ------- ------- 384,752 153,098 517,749 167,211 ------- ------- ------- -------
Total acreage at December 31, 1996 797,797 333,136 691,815 252,585 ------- ------- ------- ------- ------- ------- ------- -------
Total acreage at December 31, 1995 496,480 211,615 172,354 83,006 ------- ------- ------- ------- ------- ------- ------- -------
(1) Developed acres are those acres which are spaced or assigned to productive wells. (2) Undeveloped acres are considered to be those acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. It should not be confused with undrilled acreage held by production under the terms of a lease. (3) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. (4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
During 1996, the Company's gross and net developed acreage increased approximately 61% and 57%, respectively, and gross and net undeveloped acreage increased approximately 301% and 204%, respectively. The increases were due primarily to the purchase of Canadian Forest.
Approximately 29% of the Company's total net undeveloped acreage is under leases that have terms expiring in 1997, if not held by production, and another approximately 8% of net undeveloped acreage will expire in 1998 if not also held by production.
DRILLING ACTIVITY
Forest and its subsidiaries owned interests in gross and net exploratory and development wells for the years ended December 31, 1996, 1995 and 1994 as set forth below. This information does not include wells drilled under farmout agreements.
United States Canada -------------------- ------ 1996 1995 1994 1996 ---- ---- ---- ----
Gross Exploratory Wells: Dry (1) 4 3 2 4 Productive (2) 9 1 2 2 --- --- --- ---- 13 4 4 6 --- --- --- ---- --- --- --- ----
Net Exploratory Wells:(3) Dry (1) 2.0 1.3 2.0 2.9 Productive (2) 3.5 .3 1.3 1.4 --- --- --- ---- 5.5 1.6 3.3 4.3 --- --- --- ---- --- --- --- ----
Gross Development Wells: Dry (1) 3 - - 4 Productive (2) 15 6 5 70 --- --- --- ---- 18 6 5 74 --- --- --- ---- --- --- --- ----
Net Development Wells:(3) Dry (1) .5 - - .9 Productive (2) 1.9 .6 2.1 19.9 --- --- --- ---- 2.4 .6 2.1 20.8 --- --- --- ---- --- --- --- ----
(1) A dry well (hole) is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. (2) Productive wells are producing wells and wells capable of production, including wells that are shut-in. (3) A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
FARMOUT AGREEMENTS
Under a farmout agreement, 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.
In 1996, eleven development wells and one exploratory well were drilled in the United States under farmout agreements. Nine of the development wells were productive and two were dry holes. The exploratory well was a dry hole. In Canada, twelve development wells and five exploratory wells were drilled in 1996 under farmout agreements. Ten of the development wells were productive and two were dry holes. Three of the exploratory wells were productive and two were dry holes.
PRESENT ACTIVITIES
At December 31, 1996 Forest and its subsidiaries had four development wells that were in the process of being drilled. Two wells (both in Canada) were determined to be productive in 1997 and two wells (one in the U.S. and one in Canada) were determined to be dry holes. An additional development well was being drilled in Canada under a farmout agreement. This well was subsequently determined to be productive.
DELIVERY COMMITMENTS
At December 31, 1996 Forest and its subsidiaries were obligated to deliver, or to make cash settlement with respect to, approximately 4 BCF of natural gas under the terms of volumetric production payments. The delivery commitments cover approximately 9% of the estimated net proved reserves of natural gas attributable to the subject properties. The production payments are nonrecourse to other properties owned by the Company. For further information concerning the Company's volumetric production payment agreements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 6 and 18 of Notes to Consolidated Financial Statements. The Company is further obligated to deliver approximately .6 BCF of natural gas under existing long-term contracts in the U.S.
A significant portion of Canadian Forest's natural gas production is sold through the ProMark Netback Pool. At December 31, 1996 the ProMark Netback Pool had entered into fixed price contracts to sell approximately 10.7 BCF of natural gas in 1997 at an average price of $1.66 per MCF and approximately 5.4 BCF of natural gas in 1998 at an average price of approximately $1.88 per MCF. Canadian Forest is obligated to deliver approximately 25% of the volumes of natural gas subject to these contracts.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Royalty owners had filed two separate class action lawsuits against the Company in the State District Court of Caddo County, Oklahoma. In each case the plaintiff alleged unjust enrichment, breach of fiduciary duty, constructive fraud and breach of contract. The claims in both suits were based on the allegation that the Company underpaid royalties on the consideration received pursuant to settlement agreements with ONEOK, Inc. in 1990 and 1992.
MODRALL V. FOREST OIL CORPORATION, Case No. CJ-95-67, was filed on March 24, 1995, and the Court, on September 13, 1995, certified a class comprised of the royalty and overriding royalty owners in the three wells involved in the 1992 ONEOK, Inc. settlement. MERCO OF OKLAHOMA, INC. V. FOREST OIL CORPORATION, Case No. CJ-95-230, was filed on September 27, 1995. This suit involves the 1990 ONEOK, Inc. settlement. The plaintiffs in both suits sought actual damages in excess of $10,000, punitive damages in excess of $10,000, an accounting, interest and costs. There had been no specific determination of the amount in controversy in either case.
The plaintiffs alleged in both cases that they were entitled to share in all value received by the Company under the aforesaid settlements, including proceeds not attributable to actual gas production. As a result of a ruling by the Oklahoma Supreme Court in a case involving similar issues, both of these cases were dismissed without prejudice on September 12, 1996.
The Company entered into a Settlement Agreement and Release with El Paso Natural Gas Company ("El Paso"), effective May 15, 1987, which was later modified by a Partial Termination of Settlement Agreement and Release and Gas Purchase Agreement, effective January 1, 1989. These agreements settled the parties' disputes concerning take-or-pay deficiencies under eight gas purchase contracts covering 16 wells located in Washita County, Oklahoma. The Company received a demand letter dated November 22, 1995 from the same attorney who represented Modrall and Merco, on behalf of a royalty owner in one of the wells covered by the El Paso settlements. A class action petition was filed January 19, 1996 in WRIGHT v. FOREST OIL CORPORATION, et al., Case No. CJ-96-6 in the State District Court of Washita County, Oklahoma. Like the plaintiffs in the MODRALL and MERCO cases, the plaintiff in this case contended that Forest underpaid royalties on the consideration it received under the El Paso settlement. He asserted claims for breach of contract, unjust enrichment, breach of fiduciary duty, constructive fraud and bad faith breach of contract, and sought an accounting and an unspecified amount of actual and punitive damages, interest and costs. This case was also dismissed without prejudice on September 12, 1996 for the same reasons as set forth above.
A Petition for Rehearing asking the Oklahoma Supreme Court to reconsider its ruling in the related case was denied.
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, or those discussed above, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, liquidity or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
ITEM 4A. EXECUTIVE OFFICERS OF FOREST
The following information with respect to the executive officers of Forest is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
Years with Name (A) Age Forest Office (B) - ---------------- --- ---------- ----------
William L. Dorn* 48 25 Chairman of the Board and Chairman of the Executive Committee. Chief Executive Officer until December 1995. President until November 1993. Chairman of the Nominating Committee.
Robert S. Boswell* 47 11 President since November 1993 and Chief Executive Officer since December 1995. Vice President until November 1993 and Chief Financial Officer until December 1995. Member of the Executive Committee. Director of C.E. Franklin Ltd. and Saxon Petroleum Inc.
David H. Keyte 40 9 Vice President and Chief Financial Officer since December 1995. Vice President and Chief Accounting Officer from December 1993 until December 1995. Prior thereto Corporate Controller. Chairman of the Company's Employee Benefits Committee. Director of Saxon Petroleum Inc.
Bulent A. Berilgen 48 12 Vice President and Chief Technical Officer since May 1996. Prior thereto Vice President of Operations from December 1993 to May 1996. Prior thereto Vice President - Engineering and Development since January 1992. Director of Saxon Petroleum Inc.
Forest D. Dorn 42 19 Vice President-Gulf Coast Region since August 1996. Vice President from February 1991 and General Business Manager from December 1993 to August 1996. Prior thereto General Manager - Operations since January 1992.
Years with Name (A) Age Forest Office (B) - ---------------- --- ---------- ----------
Neal A. Stanley 49 - Vice President - Western Region since August 1996. Prior thereto President of Teton Oil and Gas Corporation.
V. Bruce Thompson 49 2 Vice President and General Counsel since August 1994. Vice President - Legal of Mid-America Dairymen, Inc. from November 1993 to August 1994. Chief of Staff for Oklahoma Congressman James M. Inhofe until November 1993.
Kenton M. Scroggs 44 13 Vice President since December 1993 and prior thereto Treasurer. Member of the Company's Employee Benefits Committee.
Daniel L. McNamara 51 25 Secretary and Corporate Counsel. Member of the Company's Employee Benefits Committee.
Joan C. Sonnen 43 7 Controller since December 1993. Prior thereto Director of Financial Accounting and Reporting. ____________ *Also a Director
(A) William L. Dorn and Forest D. Dorn are brothers.
(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
COMMON STOCK
Forest Oil Corporation has one class of common equity securities outstanding, its Common Stock, par value $.10 per share (Common Stock). On January 5, 1996, the Company's shareholders approved a reverse stock split of the Common Stock. The reverse stock split resulted in the reclassification of each five shares of Common Stock outstanding into one share.
On February 28, 1997 32,557,469 shares of Common Stock were held by 1,745 holders of record.
Forest's Common Stock is traded on the Nasdaq National Market. The high and low intraday sales prices of the Common Stock for each quarterly period of the years presented as reported by the Nasdaq National Market are listed in the chart below. All of the following quotations have been adjusted to reflect the 5 to 1 reverse stock split of the Common Stock that occurred on January 8, 1996. There were no dividends on Common Stock in 1995, 1996 or in the first quarter of 1997.
High Low ---- --- ---- First Quarter $ 12-3/16 $ 6-7/8 Second Quarter 11-7/8 7-3/16 Third Quarter 15-5/8 8-1/8 Fourth Quarter 16-9/16 10-5/8
---- First Quarter $ 16-1/2 $ 10-1/2 Second Quarter 13-5/8 11-1/4 Third Quarter 14-3/4 12-1/2 Fourth Quarter 17-7/8 12-3/8
---- First Quarter (through February 28) $ 19-3/8 $ 13-1/4
$.75 CONVERTIBLE PREFERRED STOCK
The Company called for redemption on February 28, 1997 all 2,877,673 shares of its $.75 Convertible Preferred Stock. The redemption price was $10.00 per share plus accumulated and unpaid dividends to and including the date of redemption (for an aggregate redemption price of $10.06 per share). In lieu of cash redemption, prior to the close of business on February 21, 1997 the holders of the preferred shares had the right to convert each share into 0.7 share of Forest's Common Stock; 2,783,945 shares or 96.7% of the shares outstanding were converted into Forest's Common Stock. The remaining 93,728 preferred shares that were not tendered for conversion were redeemed by Forest at the redemption price of $10.06 per share (at a total cost to Forest of $942,904). Lehman Brothers Inc. purchased 65,616 shares of Forest Oil Common Stock to fund the cash requirement of the redemption in accordance with the terms of its standby purchase agreement with Forest.
DIVIDEND RESTRICTIONS
The only restrictions on Forest's 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, and (iii) the Company's Second Amended and Restated Credit Agreement dated January 31, 1997 with The Chase Manhattan Bank (Chase), as agent for a group of banks (the Credit Facility), under which the Company is restricted in amounts it may pay as dividends (other than dividends payable in Common Stock). Under these dividend restrictions, the Company was not prohibited from paying cash dividends on its Common Stock as of March 15, 1997.
The Company has not paid dividends on its Common Stock during the past five years and does not anticipate that it will do so in the foreseeable future. The future payments of dividends, if any, on the Common Stock is within the discretion of the Board of Directors and will depend on the Company's earnings, capital requirements, financial condition and other relevant factors. There is no assurance that Forest will pay any dividends. For further information regarding the Company's equity securities and its ability to pay dividends on its Common Stock, see Notes 5, 8 and 9 of Notes to Consolidated Financial Statements.
RECENT SALES OF UNREGISTERED SECURITIES
On August 1, 1996 the Company issued 2,250,000 shares of Common Stock to Anschutz pursuant to the exercise of an option at a price of $11.64 per share. On November 5, 1996 the Company issued Anschutz 388,888 shares of Common Stock pursuant to the exercise of a warrant at a price of $10.50 per share. On November 5, 1996 the Company issued 2,000,000 shares of Common Stock to JEDI for the extinguishment of approximately $43,000,000 of debt. These transactions were exempt from registration under the Securities Act of 1933 (the 33 Act) pursuant to Section 4(2) of the 33 Act. On November 5, 1996 Anschutz also acquired 1,240,000 shares of Common Stock pursuant to the conversion of 620,000 shares of the Company's Second Series Preferred Stock in a transaction exempt from registration pursuant to Section 3(a)(9) of the 33 Act.
ITEM 6.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
- ------------------- (1) Effective January 1, 1994 the Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method. See Note 1 of Notes to Consolidated Financial Statements. (2) Financial data for the year ended December 31, 1992 include the effects of a gas contract settlement, which increased total revenue by $37,541,000 and net earnings by $24,043,000 or $8.73 per share. The average price received for natural gas for the year ended December 31, 1992 excludes the effects of the settlement. (3) Fully diluted earnings (loss) per share was the same as primary earnings (loss) per share in all years except 1992. In 1992, fully diluted earnings per share was $1.45. (4) Includes amounts attributable to required deliveries under volumetric production payments. See Notes 6 and 18 of Notes to Consolidated Financial Statements. (5) Amounts shown for 1995 exclude the effects of a gas contract settlement. Including such amount, the average sales price for 1995 was $1.90 per MCF. For further information regarding the gas contract settlement, see 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). Net earnings for 1996 were $3,305,000 compared to a net loss of $17,996,000 in 1995. Earnings for the 1996 period include an extraordinary gain on extinguishment of debt of $2,166,000. The improved earnings from continuing operations in 1996 were attributable primarily to increased natural gas and liquids prices as well as increased natural gas and liquids production as a result of the acquisitions of Saxon Petroleum Inc. (Saxon) and Canadian Forest Oil Ltd. (Canadian Forest), which were completed in December 1995 and January 1996, respectively, and to the contribution made by Forest's Canadian marketing and processing subsidiary (ProMark), which was also acquired in January 1996. The net loss for 1995 was $17,996,000 compared to a net loss of $81,843,000 in 1994. The 1995 loss was primarily due to decreased oil and natural gas volumes and lower natural gas prices, offset by $4,263,000 of income associated with a gas contract settlement. The 1994 loss included a $58,000,000 writedown of the book value of the Company's oil and gas properties due to a ceiling test limitation and a charge of $13,990,000 relating to the change in the method of accounting for oil and gas sales from the sales method to the entitlements method. See "Accounting Policies".
REVENUE. Total revenue increased 285% to $317,474,000 in 1996 from $82,456,000 in 1995 and decreased 29% in 1995 from $115,947,000 in 1994. The significant increase in total revenue in 1996 is due primarily to the acquisitions of ProMark, Canadian Forest and Saxon.
Marketing and processing revenue attributable to the marketing activities of ProMark subsequent to its purchase on January 31, 1996 was $187,374,000. For the eleven months ended December 31, 1996 ProMark marketed approximately 851 MMCF of natural gas per day.
Oil and gas sales revenue increased to $128,713,000 in 1996 from $82,275,000 in 1995, or by approximately 56%. Oil and gas sales in 1995 included $4,263,000 of income associated with a gas contract settlement with Columbia Gas Transmission ("Columbia"). The Company had entered into gas sales contracts with Columbia which were rejected by Columbia in connection with its bankruptcy proceedings. The income related to the settlement with Columbia represented approximately 5% of total oil and gas sales in 1995. Natural gas and liquids volumes increased 27% and 134% in 1996, respectively, primarily as a result of the Canadian acquisitions and new production from the Company's offshore Gulf of Mexico platform at High Island 116, partially offset by anticipated production declines in the United States. The average sales price received for natural gas in 1996 increased 7% compared to 1995, exclusive of the effects of income associated with the gas contract settlement. The average sales price received for liquids production in 1996 increased 11% compared to 1995.
Oil and gas sales revenue decreased to $82,275,000 in 1995 from $114,541,000 in 1994, or by approximately 28%. In 1995, natural gas and oil production volumes were down 31% and 24%, respectively, compared to 1994. These decreases resulted primarily from limited capital expenditures in 1994 and 1995 that did not allow the Company to replace existing production through acquisitions and drilling. The average sales price for natural gas in 1995 decreased 7% compared to 1994, exclusive of the effects of the income associated with the gas contract settlement. The average sales price for oil in 1995 increased 7% compared to 1994.
Oil and gas sales to Enron and certain of its affiliates (Enron Affiliates), the Company's largest customer, represented approximately 25% of oil and gas sales in 1996, compared to 38% in 1995 and 51% in 1994. The decreases during these periods are attributable primarily to the decreases in delivery requirements pursuant to volumetric production payments. In addition, the Company's spot market sales to Enron Affiliates increased to approximately 11 BCFE in 1996 from approximately 8 BCFE in 1995 as a result of higher production volumes available for sale. Spot market sales to Enron Affiliates in 1994 were approximately 16 BCFE.
The production volumes and average sales prices for the years ended December 31, 1996, 1995 and 1994 for Forest and its subsidiaries were as follows:
Years Ended December 31, ---------------------------- 1996 (5) 1995 1994 -------- ---- ---- NATURAL GAS
Total production (MMCF)(1) 42,496 33,342 48,048 Sales price received (per MCF)(2) $ 2.06 1.65 1.86 Effects of energy swaps (per MCF)(3) (.17) .12 .04 ------ ------ ------ Average sales price (per MCF)(2) $ 1.89 1.77 1.90
LIQUIDS
Oil and condensate: Total production (MBBLS)(4) 2,272 1,121 1,482 Sales price received (per BBL) $20.38 16.36 14.97 Effects of energy swaps (per BBL)(3) (1.50) (.50) (.14) ------ ------ ------ Average sales price (per BBL) $18.88 15.86 14.83
Natural gas liquids: Total production (MBBLS) 477 52 61 Average sales price (per BBL) $11.46 15.81 14.79
Total liquids production (MBBLS) 2,749 1,173 1,543 Average sales price (per BBL) $17.59 15.86 14.83
- ------------------- (1) Total natural gas production includes scheduled deliveries under volumetric production payments, net of royalties, of 3,168 MMCF, 9,120 MMCF and 16,005 MMCF in 1996, 1995 and 1994, respectively. Natural gas delivered pursuant to volumetric production payment agreements represented approximately 7%, 27% and 33% of total natural gas production in 1996, 1995 and 1994, respectively. For further information concerning volumes and prices recorded under volumetric production payments, see Notes 6 and 18 of Notes to Consolidated Financial Statements. (2) Amounts shown for 1995 exclude the effects of a gas contract settlement. Including such amount, the sales price received and average sales price for natural gas in 1995 were $1.78 and $1.90 per MCF, respectively. For further information regarding the gas contract settlement, see Note 15 of Notes to Consolidated Financial Statements. (3) Energy swaps were entered into to hedge the price of spot market volumes against price fluctuation. Hedged natural gas volumes were 12,741 MMCF, 10,146 MMCF and 12,184 MMCF for the years ended December 31, 1996, 1995 and 1994, respectively. Hedged oil and condensate volumes were 895,600 barrels, 498,000 barrels and 370,000 barrels for the years ended December 31, 1996, 1995 and 1994, respectively. The aggregate gains (losses) under energy swap agreements were $(10,422,000), $3,536,000 and $1,810,000, respectively, for the years ended December 31, 1996, 1995 and 1994. (4) An immaterial amount of oil production is covered by scheduled deliveries under volumetric production payments. (5) Alberta's royalty program was restructured in 1994 and remained uncertain throughout much of 1995 and 1996. Production of natural gas liquids for the year ended December 31, 1996 was reduced by 79,000 barrels as a result of royalty adjustments, resulting in an increase in the reported average sales price for natural gas liquids to $11.46 per barrel from $9.70 or by approximately 18%. The royalty adjustments did not have a significant effect in reported volumes or average sales prices for natural gas or oil and condensate. Canadian Forest continues to receive additional information with respect to royalty calculations and anticipates that revisions to such calculations will continue to occur throughout 1997. The effects of future royalty adjustments cannot be predicted at this time.
Miscellaneous net revenue of $1,387,000 in 1996 included the reversal of a $1,136,000 liability for royalties on the proceeds from the gas contract settlement with Columbia. Miscellaneous net revenue was $181,000 in 1995. Miscellaneous net revenue of $1,406,000 in 1994 included income from the sale of miscellaneous pipeline systems and equipment and the reversal of an accounts receivable reserve, partially offset by a reserve for settlement of a
royalty dispute and a payment of deferred maintenance costs of a real estate complex formerly used for general business purposes.
MARKETING AND PROCESSING EXPENSE. In 1996, marketing and processing expense of $178,706,000 was recorded which relates primarily to the marketing activities of ProMark subsequent to its purchase on January 31, 1996.
OIL AND GAS PRODUCTION EXPENSE. Oil and gas production expense increased 43% to $32,199,000 in 1996 from $22,463,000 in 1995 due primarily to production expense associated with the newly-acquired Canadian properties. On an MCFE basis, production expense was $.55 per MCFE in 1996 compared to $.56 in 1995. Oil and gas production expense increased slightly to $22,463,000 in 1995 from $22,384,000 in 1994. On an MCFE basis, however, production expense increased to $.56 per MCFE in 1995 from $.39 per MCFE in 1994. The increased cost per MCFE from 1994 to 1995 is directly attributable to fixed components of oil and gas production expense being allocated over a smaller production base.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased 50% to $13,623,000 in 1996 compared to $9,081,000 in 1995 due primarily to the effect of Canadian acquisitions. General and administrative expense decreased 19% to $9,081,000 in 1995 compared to $11,166,000 in 1994 due primarily to a reduction in the size of the Company's workforce on March 1, 1995. The capitalization rate was approximately 36% in 1996 compared to 43% in 1995 and 40% in 1994. Changes in the capitalization rate result from changes in the percentage of employees' time spent working directly on exploration and development projects.
Total overhead costs (capitalized and expensed general and administrative costs) were $21,396,000 in 1996, $15,857,000 in 1995 and $18,719,000 in 1994. Total overhead costs were approximately 35% higher in 1996 compared to 1995 due primarily to the addition of the Canadian operations, which increased Forest's salaried workforce to 179 at December 31, 1996 compared to 115 at December 31, 1995. Total overhead costs were approximately 15% lower in 1995 than in 1994. The Company's salaried workforce in the United States was 115 at December 31, 1995 compared to 143 at December 31, 1994. The decreases in total overhead costs and personnel in 1995 were due primarily to a reduction in the size of the Company's workforce effective March 1, 1995. The following table summarizes the total overhead costs incurred during the periods:
Years Ended December 31, ------------------------ 1996 1995 1994 ---- ---- ---- (In Thousands)
Overhead costs capitalized $ 7,773 6,776 7,553 General and administrative costs expensed (1) 13,623 9,081 11,166 ------- ------ ------ Total overhead costs $21,396 15,857 18,719 ------- ------ ------ ------- ------ ------
(1) Includes $2,555,000 in 1996 related to marketing and processing operations.
INTEREST EXPENSE. Interest expense of $23,307,000 in 1996 decreased $2,016,000 or 8% compared to 1995 due primarily to the restructuring and extinguishment of the nonrecourse secured loan and lower effective interest on the dollar denominated production payment. Interest expense of $25,323,000 in 1995 decreased $1,450,000 or 5% compared to 1994 due primarily to lower effective interest rates related to the nonrecourse secured loan and the dollar denominated production payment.
DEPRECIATION AND DEPLETION EXPENSE. Depreciation and depletion expense increased 45% to $63,068,000 in 1996 from $43,592,000 in 1995 due to the increase in production, offset by a decrease in the depletion rate per unit of production. The depletion rate decreased to $1.01 per MCFE in 1996 compared to $1.06 per MCFE in 1995, resulting from the addition of lower cost Canadian production, partially offset by higher anticipated future costs in the United States due to expected increased costs for services. Depreciation and depletion expense decreased 33%
to $43,592,000 in 1995 from $65,468,000 in 1994 due to decreased production, as well as a decrease in the depletion rate per unit of production. The depletion rate decreased to $1.06 per MCFE for United States production in 1995 compared to $1.13 in 1994 due to writedowns of the Company's oil and gas properties taken in the third and fourth quarters of 1994.
At December 31, 1996 the Company had undeveloped properties with a cost basis of approximately $30,046,000 in the U.S. and $13,870,000 in Canada which were excluded from depletion compared to $28,380,000 in the U.S. at December 31, 1995 and $30,441,000 in the U.S. at December 31, 1994. The increase in 1996 compared to 1995 is due primarily to the acquisition of undeveloped properties in the Canadian Forest purchase.
IMPAIRMENT OF OIL AND GAS PROPERTIES. The Company was not required to record a writedown of the carrying value of its oil and gas properties in 1996 or 1995. The Company recorded a writedown of its oil and gas properties of $58,000,000 in 1994 due primarily to a decrease in spot market prices for natural gas.
The average Gulf Coast spot price received by the Company for natural gas decreased from $3.89 per MCF at December 31, 1996 to approximately $1.80 per MCF at March 1, 1997. The West Central Texas Intermediate price for crude oil decreased from $23.75 per barrel at December 31, 1996 to approximately $18.00 per barrel at March 1, 1997. The average spot price received for Canadian natural gas production decreased from $2.76 per MMBTU at December 31, 1996 to approximately $1.82 per MMBTU at March 1, 1997. The Canadian spot price received for crude oil decreased from $25.92 per barrel at December 31, 1996 to approximately $20.30 per barrel at March 1, 1997.
Writedowns of the full cost pools in the United States and Canada may be required if the depressed price environment persists, undeveloped property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any.
ACCOUNTING POLICIES. The Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994. Under the sales method previously used by the Company, all proceeds from production credited to the Company were recorded as revenue until such time as the Company had produced its share of related reserves. Under the entitlements method, revenue is recorded based upon the Company's share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced. Under the entitlements method, the Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue. The Company believes that the entitlements method is preferable because it allows for recognition of revenue based on the Company's actual share of jointly owned production and provides a better matching of revenue and related expenses. The cumulative effect of the change for the periods through December 31, 1993, was a charge of $13,990,000. The effect of this change on 1994 was an increase in earnings from operations of $3,584,000 and an increase in production volumes of 1,555,000 MCF. There were no related income tax effects in 1994.
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of" (SFAS No. 121). Oil and gas properties accounted for under the full cost method of accounting are excluded from the scope of SFAS No. 121, but will continue to be subject to the ceiling test limitation. SFAS No. 121 requires that impairment losses be recorded on other long-lived assets used in operations when indicators of impairment are present and either the undiscounted future cash flows estimated to be generated by those assets or the fair market value are less than the assets' carrying amount. SFAS No. 121 also addresses the accounting for long-lived assets that are expected to be disposed of. The Company adopted SFAS No. 121 effective January 1, 1996. The adoption of SFAS No. 121 had no effect on the Company's financial statements.
Statement of Financial Accounting Standards No. 123, "Accounting for Stock Based Compensation" (SFAS No. 123), was issued by the Financial Accounting Standards Board in October 1995. SFAS No. 123 establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. The Company adopted SFAS No. 123 effective January 1, 1996, and will continue to use the measurement method prescribed by APB Opinion 25, as permitted under SFAS No. 123. The Company has included the pro forma disclosures required by SFAS No. 123 in Note 9 of Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically addressed its long-term liquidity needs through the issuance of debt and equity securities, when market conditions permit, and through the use of nonrecourse production-based financing.
In 1995, the Company completed a series of transactions with Anschutz and JEDI. For total consideration of $45,000,000, the Company issued to Anschutz 3,760,000 shares of Common Stock, 620,000 shares of a new series of convertible preferred stock and a warrant that entitled Anschutz to purchase 3,888,888 shares of Common Stock for $10.50 (the A Warrant). The Company restructured JEDI's existing loan, which had a principal balance of approximately $62,368,000 before unamortized discount of $4,984,000, into two tranches: a $40,000,000 tranche and an approximately $22,400,000 tranche. In consideration for the loan restructuring JEDI received a warrant to purchase 2,250,000 shares of Common Stock at $10.00 per share (the B Warrant). JEDI granted an option to Anschutz (the Anschutz Option) to purchase from JEDI shares purchased pursuant to the B Warrant at an escalating price ranging from $10.00 to $15.50 per share. In December 1995, JEDI exchanged the $22,400,000 tranche and the B Warrant for 1,680,000 shares of Common Stock. In connection with this exchange, the Company assumed JEDI's obligations under the Anschutz Option. Under the Anschutz Option, the Company was then obligated to issue shares directly to Anschutz that previously would have been issued to JEDI pursuant to the B Warrant.
In 1996, the Company completed additional transactions that improved its financial position considerably. On January 31, 1996 the Company and Saxon sold 13,200,000 shares of common stock for $11.00 per share in a public offering (the 1996 Public Offering). Of this amount, 1,060,000 shares were sold by Saxon and 12,140,000 shares were sold by Forest. The net proceeds to Forest from the issuance of the shares totaled approximately $125,000,000 after deducting issuance costs and underwriting fees and were used, along with an additional approximately $8,300,000 drawn under the Company's Credit Facility to complete the purchase of Canadian Forest and ProMark. The net proceeds to Saxon of approximately $11,000,000 were used to reduce its bank debt.
On August 1, 1996 Anschutz exercised the Anschutz Option to purchase 2,250,000 shares of common stock for $26,200,000 or approximately $11.64 per share. Proceeds received by Forest were used primarily to fund a portion of 1996 capital expenditures.
On November 5, 1996 the Company exchanged 2,000,000 shares of common stock plus approximately $13,500,000 in cash to extinguish approximately $43,000,000 of nonrecourse secured debt owed to JEDI. The JEDI debt bore interest at 12-1/2% per annum. In connection with this transaction, Anschutz acquired 1,628,888 shares of common stock by exercising a portion of the A Warrant to purchase 388,888 shares of common stock at $10.50 per share and by converting 620,000 shares of Forest's Second Series Preferred Stock into 1,240,000 shares of common stock. The fair value of the shares of common stock issued to JEDI was estimated based on the quoted market price of the common stock at the date of the transaction, less a discount of 7-1/2% to reflect the lock-up agreement with JEDI that limited JEDI's ability to transfer the shares before May 31, 1997, the size of the block of shares to be issued and the estimated brokerage fees on the ultimate disposition of the shares. The fair value of the common stock issued and the cash paid to JEDI, including related expenses of the transaction, was less than the carrying amount of the debt extinguished. Accordingly, the Company recorded an extraordinary gain on extinguishment of debt in the fourth quarter of 1996 of approximately $2,166,000.
On November 14, 1996 the Company filed a shelf registration with the Securities and Exchange Commission to issue up to $250,000,000 in one or more forms of debt or equity securities. Except as otherwise provided in an applicable prospectus supplement, the net proceeds from the sale of the securities will be used for the acquisition of oil and gas properties, capital expenditures, the repayment of subordinated debentures or other debt, repayments of borrowings under revolving credit agreements, or for other general corporate purposes.
On February 7, 1997 the Company called for redemption all 2,877,673 shares of its $.75 Convertible Preferred Stock. This conversion eliminated all outstanding preferred stock from Forest's capital structure. In response to its call for redemption, 2,783,945 shares or 96.7% of the shares outstanding were tendered for conversion into common stock on or before the February 21, 1996 deadline. The remaining 93,728 preferred shares that were not tendered for conversion were redeemed by the Company at the redemption price of $10.06 per share (at a total cost of $942,904) on February 28, 1997. Lehman Brothers Inc. purchased 65,616 shares of the Company's common stock to fund the cash requirement of the redemption in accordance with the terms of its standby purchase agreement with Forest. Redemption of the $.75 Convertible Preferred Stock eliminates approximately $2,200,000 of annual preferred dividend payments.
Many of the factors which may affect the Company's future operating performance and long-term liquidity are beyond the Company's control, including, but not limited to, oil and natural gas prices, governmental actions and taxes, the availability and attractiveness of properties for acquisition, the adequacy and attractiveness of financing and operational results. The Company continues to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, preferred stock or other equity securities of the Company, the issuance of net profits interests, sales of non-strategic assets, prospects and technical information, or joint venture financing. Availability of these sources of capital and, therefore, the Company's ability to execute its operating strategy will depend upon a number of factors, some of which are beyond the control of the Company.
CASH FLOW. Historically, one of the Company's primary sources of capital has been net cash provided by operating activities (operating cash flow). The following summary table reflects comparative cash flow data for the Company for the years ended December 31, 1996, 1995 and 1994.
Years Ended December 31, ------------------------ 1996 1995 1994 ---- ---- ---- (In Thousands)
Net cash provided (used) by operating activities $ 67,815 (3,062) 42,441 Net cash used by investing activities (226,867) (17,219) (32,307) Net cash provided (used) by financing activities 164,500 20,698 (14,126)
Net cash provided by operating activities increased to $67,815,000 in 1996 compared to a net use of cash for operating activities of $3,062,000 in 1995, due to higher natural gas and liquids prices, increased natural gas and liquids production as a result of the Saxon and Canadian Forest acquisitions and the contribution made by ProMark and an increase in accounts payable during 1996. The Company used $226,867,000 for investing activities in 1996 compared to $17,219,000 in 1995. The increase is due primarily to the use of funds to acquire Canadian Forest and higher capital expenditures. Cash provided by financing activities was $164,500,000 in 1996 compared to $20,698,000 in 1995. The increase is due primarily to the net proceeds received from the 1996 Public Offering and the exercise by Anschutz of options and warrants.
CAPITAL EXPENDITURES. The Company's expenditures for property acquisition, exploration and development for the past three years were as follows:
Years Ended December 31, ---------------------------- 1996 1995 1994 ---- ---- ---- (In Thousands)
Property acquisition costs (1): Proved properties $140,875 26,487 9,553 Undeveloped properties 18,080 320 209 -------- ------ ----- 158,955 26,807 9,762
Exploration costs: Direct costs 40,831 11,528 15,229 Overhead capitalized 2,608 1,211 464 -------- ------ ----- 43,439 12,739 15,693
Development costs: Direct costs 36,559 7,633 10,000 Overhead capitalized 5,165 5,565 7,089 -------- ------ ----- 41,724 13,198 17,089 -------- ------ ----- $244,118 52,744 42,544 -------- ------ ----- -------- ------ -----
(1) 1996 amounts consist primarily of the allocation of purchase price to the oil and gas properties acquired in the purchase of Canadian Forest. 1995 amounts consist primarily of the allocation of purchase price to the oil and gas properties acquired in the purchase of Saxon.
The Company's 1997 budgeted direct expenditures for exploration and development are approximately $64,000,000 and $61,000,000, respectively. Capitalized overhead in 1997 is expected to be approximately $8,000,000. The Company expects to be able to meet its 1997 capital expenditure financing requirements using cash flows generated by operations, sales of non-strategic assets and borrowings under existing lines of credit. However, there can be no assurance that the Company will have access to sufficient capital to meet its capital requirements. The planned levels of capital expenditures could be reduced if the Company experiences lower than anticipated net cash provided by operations or other liquidity needs or could be increased if the Company experiences increased cash flow or accesses additional sources of capital. The prices the Company receives for its future oil and natural gas production will significantly impact future operating cash flows. No prediction can be made as to the prices the Company will receive for its future oil and gas production.
In addition, while the Company intends to continue a strategy of acquiring reserves that meet its investment criteria, no assurance can be given that the Company can locate or finance any property acquisitions.
PENDING ACQUISITION:
On March 4, 1997 Saxon announced an offer to purchase all of the issued and outstanding Class A shares of Truax Resources Corporation (Truax). Truax shareholders may elect to receive either $2.06 CDN or two Saxon shares for each Truax share tendered, subject to certain minimum and maximum aggregate amounts of Saxon shares. The value of the offer is approximately $38,000,000 CDN. The offer expires April 8, 1997 and is subject to a minimum of two-thirds of the outstanding Class A shares of Truax being tendered and the receipt of necessary regulatory approvals. Truax has recommended that its shareholders do not tender shares pursuant to the Saxon offer. Assuming that the tender offer is successful, Forest currently intends to exercise its rights under its equity participation agreement with Saxon to purchase additional shares to maintain its majority ownership position in Saxon.
DISPOSITIONS OF NON-STRATEGIC ASSETS. As a part of its operating strategy, the Company also conducts an ongoing disposition program of its non-strategic assets. Assets with little value or which are not consistent with the Company's ongoing operating strategy are identified for sale or trade. During 1996, the Company disposed of properties with estimated proved reserves of approximately 1.5 BCF of natural gas and 628,000 barrels of oil for total net proceeds of $6,916,000. In addition, Saxon received proceeds of approximately $10,959,000 representing the liquidation of its preferred shares in Archean Energy Ltd. These shares, which were received through a series of transactions relating to the 1992 sale of the Company's Canadian oil and gas properties, were transferred to Saxon by Forest in 1995.
In 1995, the Company disposed of properties with estimated proved reserves of approximately 2.4 BCF of natural gas and 6,000 barrels of oil for total net proceeds of $8,715,000.
BANK CREDIT FACILITIES. Under the Credit Facility with Chase, as amended, the Company may borrow up to $60,000,000 for working capital and/or general corporate purposes. The borrowing base is subject to formal redeterminations semi-annually, but may be changed at the banks' discretion at any time. The Credit Facility is secured by a lien on, and a security interest in, a majority of the Company's U.S. proved oil and gas properties and related assets (subject to prior security interests granted to holders of volumetric production payment agreements) and a pledge of accounts receivable. The maturity date of the Credit Facility is January 31, 2000. Under the terms of the Credit Facility, the Company is subject to certain covenants and financial tests, including restrictions or requirements with respect to working capital, cash flow, additional debt, liens, asset sales, investments, mergers, cash dividends and reporting responsibilities. At December 31, 1996 the outstanding balance under this facility was $26,400,000. The Company has also used the facility for a $1,500,000 letter of credit.
On February 8, 1996 a newly-formed Canadian subsidiary of Forest entered into a credit agreement (the Canadian Credit Facility) with The Chase Manhattan Bank of Canada for the benefit of Canadian Forest and ProMark. The borrowing base under the Canadian Credit Facility is $60,000,000 CDN. The borrowing base is subject to formal redeterminations semi-annually, but may be changed by the bank at its discretion at any time. The maturity date of the Canadian Credit Facility is February 7, 1999. The Canadian Credit Facility is indirectly secured by substantially all the assets of Canadian Forest. Funds drawn under the Canadian Credit Facility can be used for general corporate purposes. Under the terms of the Canadian Credit Facility, the three Canadian subsidiaries are subject to certain covenants and financial tests, including restrictions or requirements with respect to working capital, cash flow, additional debt, liens, asset sales, investments, mergers, cash dividends and reporting responsibilities. At December 31, 1996 the outstanding balance under this facility was $32,500,000 (US). The Company has also used this facility for a letter of credit in the amount of $3,081,000 CDN.
In addition to the credit facilities described above, Saxon has a revolving credit facility with a borrowing base of $20,000,000 CDN. The loan is subject to semi-annual review and has demand features; however, repayments are not required provided that borrowings are not in excess of the borrowing base and Saxon complies with other existing covenants. At December 31, 1996 there were no outstanding borrowings under this facility.
At February 28, 1997 the amount outstanding under the Credit Facility was $34,600,000, the amount outstanding under the Canadian Credit Facility was $33,622,000 and the amount outstanding under the Saxon revolving credit facility was $7,821,000.
WORKING CAPITAL. The Company had a working capital deficit of approximately $12,649,000 at December 31, 1996 compared to a deficit of approximately $9,181,000 at December 31, 1995. The increase in the deficit is attributable primarily to an increase in accounts payable related to exploration and development activities.
The Company generally reports a working capital deficit at the end of a period. The working capital deficit is principally the result of accounts payable for capitalized exploration and development costs. Settlement of these payables is funded by cash flow from the Company's operations or, if necessary, by drawdowns on the Company's
long-term bank credit facilities. For cash management purposes, drawdowns on the credit facilities are not made until the due dates of the payables.
At December 31, 1996 the Company had available borrowing capacity of approximately $60,000,000 under its long-term bank credit facilities. The Company's available credit at December 31, 1996 was adequate to fund the working capital deficit at that date.
LONG-TERM SALES CONTRACTS. A significant portion of Canadian Forest's natural gas production is sold through the ProMark Netback Pool. At December 31, 1996 the ProMark Netback Pool had entered into fixed price contracts to sell approximately 10.7 BCF of natural gas in 1997 at an average price of $1.66 CDN per MCF and approximately 5.4 BCF of natural gas in 1998 at an average price of approximately $1.88 CDN per MCF. Canadian Forest is obligated to deliver approximately 25% of the volumes of natural gas subject to these contracts.
HEDGING PROGRAM. In addition to the volumes of natural gas and oil sold under long-term sales contracts and dedicated to volumetric production payments, the Company also uses energy swaps and other financial agreements to hedge against the effects of fluctuations in the sales prices for oil and natural gas produced. 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, 1996 the Company had natural gas swaps and collars for an aggregate of approximately 27.0 BBTU (billion British Thermal Units) per day of natural gas during 1997 at fixed prices ranging from $1.159 per MMBTU (million British Thermal Units) on an Alberta Energy Company "C" (AECO "C") basis to $2.728 per MMBTU on a New York Mercantile Exchange (NYMEX) basis and an aggregate of approximately 3.2 BBTU per day of natural gas during 1998 at fixed prices ranging from $1.159 (AECO "C" basis) to $2.540 (NYMEX basis) per MMBTU. The weighted average hedged price for natural gas under such agreements is $2.15 and $2.18 per MMBTU in 1997 and 1998, respectively. Subsequent to December 31, 1996 the Company entered into a collar to hedge 7.0 BBTU of natural gas per day from April 1997 to September 1997. The floor and ceiling price of the collar are $2.10 and $2.50 per MMBTU (NYMEX basis), respectively. At December 31, 1996 the Company had oil swaps for an aggregate of 1,964 barrels per day of oil during 1997 at fixed prices ranging from $17.90 to $21.05 (NYMEX basis). The weighted average hedged price for oil under such agreements is $19.77 per barrel. Subsequent to December 31, 1996, the Company entered into an oil swap to hedge 200 barrels of oil per day from February 1997 to July 1997 at a fixed price of $23.67 per barrel (NYMEX basis). The Company also entered into a 1998 oil swap to hedge 247 barrels per day from January 1998 to December 1998 at a fixed price of $20.00 per barrel (NYMEX basis). For further information on the Company's outstanding energy swaps, see Note 13 of Notes to Consolidated Financial Statements.
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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1996 in conformity with generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994.
KPMG PEAT MARWICK LLP
Denver, Colorado February 12, 1997
FOREST OIL CORPORATION CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ----------------- 1996 1995 ---- ---- (In Thousands) ASSETS Current assets: Cash and cash equivalents $ 8,626 3,287 Accounts receivable 55,462 17,395 Other current assets 4,996 2,557 -------- ------- Total current assets 69,084 23,239
Net property and equipment, at cost, full cost method (Notes 5 and 6) 458,242 277,599
Investment in affiliate (Note 4) - 11,301
Goodwill and other intangible assets, net 29,439 -
Other assets 6,693 8,904 -------- ------- $563,458 321,043 -------- ------- -------- -------
LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Cash overdraft $ 4,682 2,055 Current portion of long-term debt (Note 5) 2,091 2,263 Accounts payable 64,811 17,456 Accrued interest 4,584 4,029 Other current liabilities 5,565 6,617 -------- ------- Total current liabilities 81,733 32,420
Long-term debt (Notes 3 and 5) 168,859 193,879 Other liabilities 19,844 27,139 Deferred revenue (Note 6) 7,591 15,137 Deferred income taxes 33,716 -
Commitments and contingencies (Notes 10, 12 and 13)
Minority interest (Note 2) 9,272 8,171
Shareholders' equity (Notes 2, 3, 5, 8 and 9): Preferred stock 15,827 24,359 Common stock, 30,541,105 shares in 1996 (10,660,291 shares in 1995) 3,053 1,066 Capital surplus 438,556 241,241 Common shares to be issued in debt restructuring - 6,073 Accumulated deficit (214,190) (217,495) Foreign currency translation (803) (1,407) Treasury stock, at cost, none in 1996 and 1,060,000 shares in 1995 - (9,540) -------- ------- Total shareholders' equity 242,443 44,297 -------- ------- $563,458 321,043 -------- ------- -------- -------
See accompanying Notes to Consolidated Financial Statements
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, -------------------------------- 1996 1995 1994 -------- ------- ------- (In Thousands Except Per Share Amounts)
Revenue: Marketing and processing $187,374 - - Oil and gas sales: Gas 80,111 59,084 91,309 Gas contract settlement (Note 15) - 4,263 - Oil, condensate and natural gas liquids 48,602 18,928 23,232 -------- ------- ------- Total oil and gas sales 128,713 82,275 114,541
Miscellaneous, net 1,387 181 1,406 -------- ------- ------- Total revenue 317,474 82,456 115,947
Expenses: Marketing and processing 178,706 - - Oil and gas production 32,199 22,463 22,384 General and administrative 13,623 9,081 11,166 Interest 23,307 25,323 26,773 Depreciation and depletion 63,068 43,592 65,468 Minority interest in loss of subsidiary (19) - - Provision for impairment of oil and gas properties - - 58,000 -------- ------- ------- Total expenses 310,884 100,459 183,791 -------- ------- -------
Earnings (loss) before income taxes, cumulative effect of change in accounting principle and extraordinary item 6,590 (18,003) (67,844) Income tax expense (benefit) (Note 7): Current 3,943 (7) 9 Deferred 1,508 - - -------- ------- ------- 5,451 (7) 9 -------- ------- -------
Earnings (loss) before cumulative effect of change in accounting principle and extraordinary item 1,139 (17,996) (67,853)
Cumulative effect of change in accounting principle for oil and gas sales (Note 1) - - (13,990) -------- ------- ------- Earnings (loss) before extraordinary item 1,139 (17,996) (81,843)
Extraordinary item - gain on extinguishment of debt (Note 3) 2,166 - - -------- ------- ------- Net earnings (loss) $3,305 (17,996) (81,843) -------- ------- ------- -------- ------- -------
Weighted average number of common shares outstanding 27,163 7,360 5,619 -------- ------- ------- -------- ------- -------
Earnings (loss) attributable to common stock $ 1,147 (20,156) (84,004) -------- ------- ------- -------- ------- ------- Primary and fully diluted earnings (loss) per common share: Loss attributable to common stock before cumulative effect of change in accounting principle and extraordinary item $ (.04) (2.74) (12.46) Cumulative effect of change in accounting principle - - (2.49) -------- ------- -------
Loss attributable to common stock before extraordinary item (.04) (2.74) (14.95)
Extraordinary item - gain on extinguishment of debt .08 - - -------- ------- ------- Earnings (loss) attributable to common stock $ .04 (2.74) (14.95) -------- ------- ------- -------- ------- -------
See accompanying Notes to Consolidated Financial Statments
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
See accompanying Notes to Consolidated Financial Statements
FOREST OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: - -------------------------------------------------------------------------------
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION - Forest Oil Corporation is engaged in the acquisition, exploration, development, production and marketing of natural gas and crude oil in North America. The Company was incorporated in New York in 1924, the successor to a company formed in 1916, and has been publicly held since 1969. The Company is active in several of the major exploration and producing areas in and offshore the United States and in Canada.
The consolidated financial statements include the accounts of Forest Oil Corporation and its consolidated subsidiaries (Forest or the Company). Significant intercompany balances and transactions are eliminated. The Company generally consolidates all subsidiaries in which it controls over 50% of the voting interests. Entities in which the Company does not have a direct or indirect majority voting interest are generally accounted for using the equity method.
In the course of preparing the consolidated financial statements, management makes various assumptions and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts estimated.
Unless otherwise indicated, all share amounts, share prices and per share amounts have been adjusted to give effect to a 5 to 1 reverse stock split that was effective on January 8, 1996.
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. During 1996, the Company's oil and gas operations were conducted in the United States and in Canada. During 1995 and 1994, the Company's oil and gas operations were conducted solely in the United States. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. Capitalized costs applicable to each cost center are depleted using the units of production method. A reserve is provided for estimated future costs of site restoration, dismantlement and abandonment activities as a component of depletion. Unusually significant investments in unproved properties, including related capitalized interest costs, are not depleted pending the determination of the existence of proved reserves. As of December 31, 1996, 1995 and 1994, there were undeveloped property costs of $30,046,000, $28,380,000 and $30,441,000, respectively, which were not being depleted in the United States and costs of $13,870,000 which were not being depleted in Canada. Of the undeveloped costs in the United States not being depleted at December 31, 1996, approximately 46% were incurred in 1996, 9% in 1995, 3% in 1994, 40% in 1993 and 2% in 1992. All of the undeveloped properties in Canada not being depleted at December 31, 1996 were acquired in 1996.
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 thousand cubic feet (MCF) of natural gas. Depletion per unit of production (MCFE) for each of the Company's cost centers was as follows:
United States Canada ------------- ------ 1994 $1.13 - 1995 1.06 - 1996 1.12 .85
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED): - -------------------------------------------------------------------------------
Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. As a result of this limitation on capitalized costs, the accompanying financial statements include a provision for impairment of oil and gas property costs of $58,000,000 in the United States in 1994.
Gain or loss is recognized only on the sale of oil and gas properties involving significant reserves.
Buildings, transportation and other equipment are depreciated on the straight-line method based upon estimated useful lives of the assets ranging from five to forty-five years.
Net property and equipment at December 31 consists of the following:
1996 1995 ---- ---- (In Thousands)
Oil and gas properties $1,457,212 1,216,027 Buildings, transportation and other equipment 10,993 10,502 ---------- --------- 1,468,205 1,226,529
Less accumulated depreciation, depletion and valuation allowance 1,009,963 948,930 ---------- --------- $ 458,242 277,599 ---------- --------- ---------- ---------
GOODWILL AND OTHER INTANGIBLE ASSETS - Goodwill and other intangible assets recorded in the acquisition of the Company's gas marketing subsidiary consist of the following at December 31, 1996:
---- (In Thousands)
Goodwill $16,728 Gas marketing contracts 14,594 ------- 31,322
Less accumulated amortization 1,883 ------- $29,439 ------- -------
Goodwill is being amortized on a straight line basis over twenty years. The amount attributed to the value of gas marketing contracts acquired is being amortized on a straight line basis over the average life of such contracts of twelve years.
GAS MARKETING - The Company's gas marketing subsidiary, ProMark, enters into fixed price agreements to purchase and sell natural gas. ProMark's general strategy for this business is to enter into offsetting purchase and sales contracts. Net open positions relating to these contracts do occur, but have not been significant to date. Revenue from the sale of the gas is recorded as marketing revenue and the cost of the gas sold is recorded as marketing expense.
ProMark also provides natural gas marketing aggregation services for third parties. Fees earned for such services are recorded as marketing revenue as the services are performed.
OIL AND GAS SALES - The Company changed its method of accounting for oil and gas sales from the sales method to the entitlements method effective January 1, 1994. Under the sales method previously used by the Company, all proceeds from production credited to the Company were recorded as revenue until such time as the Company had produced its share of related reserves. Under the entitlements method, revenue is recorded based upon the Company's share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED): - -------------------------------------------------------------------------------
Under the entitlements method, the Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue. The Company believes that the entitlements method is preferable because it allows for recognition of revenue based on the Company's actual share of jointly owned production and provides a better matching of revenue and related expenses.
The cumulative effect of the change for the periods through December 31, 1993 was a charge of $13,990,000. The effect of this change on 1994 was an increase in earnings from operations of $3,584,000 and an increase in production volumes of 1,555,000 MCF. There were no related income tax effects in 1994.
As of December 31, 1996 the Company had produced approximately 2.6 BCF more than its entitled share of production. The estimated value of this imbalance of approximately $4,355,000 is included in the accompanying consolidated balance sheet as a short-term liability of $1,650,000 and a long-term liability of $2,705,000.
HEDGING TRANSACTIONS - In order to minimize exposure to fluctuations in oil and natural gas prices, the Company hedges the price of future oil and natural gas production by entering into certain contracts and financial arrangements. These instruments are accounted for as hedges when the instrument is designated as a hedge of the related production and there exists a high degree of correlation between the fair value of the instrument and the fair value of the hedged production. The degree of correlation is assessed periodically. Gains and losses related to these hedging transactions are recognized as adjustments to therevenue recorded for the related production. Costs associated with the purchase of certain hedging instruments are deferred and amortized against revenue related to the hedged production.
INCOME TAXES - The Company uses the asset and liability method of accounting for income taxes which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities.
FOREIGN CURRENCY TRANSLATION - The functional currency of the Company's Canadian operations is the Canadian dollar. Assets and liabilities related to the Company's Canadian operations are generally translated at current exchange rates, and related translation adjustments are reported as a component of shareholders' equity. Income statement accounts are translated at the average rates during the period.
EARNINGS (LOSS) PER SHARE - Primary earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares and common share equivalents outstanding during each period, excluding treasury shares. Net earnings (loss) attributable to common stock represents net earnings (loss) less preferred stock dividend requirements of $2,158,000 in 1996, $2,160,000 in 1995 and $2,161,000 in 1994. Common share equivalents include, when applicable, dilutive stock options and warrants using the treasury stock method.
Fully diluted earnings (loss) per share is computed assuming, in addition to the above, (i) that convertible preferred stock was converted at the beginning of each period or date of issuance, if later, and (ii) any additional dilutive effect of stock options and warrants. The effects of these assumptions were anti-dilutive in 1996, 1995 and 1994.
RECLASSIFICATIONS - Certain amounts in prior years' financial statements have been reclassified to conform to the 1996 financial statement presentation.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(2) ACQUISITIONS: - -------------------------------------------------------------------------------
During 1995, the Company completed acquisitions totaling $26,807,000. The most significant of these was the purchase on December 20, 1995 of a 56% economic (49% voting) interest in Saxon Petroleum Inc. (Saxon) for approximately $22,000,000. Saxon is a Canadian exploration and production company with headquarters in Calgary, Alberta and operations concentrated in western Alberta. In the transaction, Forest received from Saxon 40,800,000 voting common shares, 12,300,000 nonvoting common shares, 15,500,000 convertible preferred shares and warrants to purchase 5,300,000 common shares. The preferred shares and the nonvoting common shares of Saxon are convertible into voting common shares at any time. In exchange, Forest transferred to Saxon its preferred shares of Archean Energy, Ltd., issued to Saxon 1,060,000 common shares of Forest and paid Saxon $1,500,000 CDN. The preferred shares of Archean Energy, Ltd. were recorded at their historical carrying value of $11,301,000. The Forest common shares issued to Saxon were recorded at their estimated fair value determined by reference to the quoted market price of the shares immediately preceding the announcement of the acquisition.
Since Forest has majority voting control over Saxon as a result of the voting common shares that it owns and proxies that it holds, it has accounted for Saxon as a consolidated subsidiary from the date of its acquisition. The Company did not record any production or results of operations of Saxon for the period from December 20 to December 31, 1995 as the results of operations for such period were not significant.
The Forest common shares held by Saxon were recorded as treasury stock on Forest's consolidated balance sheet at December 31, 1995. In January 1996, Saxon sold these shares in a public offering of Forest Common Stock and used the proceeds to reduce its bank debt.
In September 1996, the preferred shares of Archean were redeemed for cash at their approximate carrying value.
Subsequent to December 31, 1996 Forest converted its preferred shares of Saxon into 27,192,983 nonvoting common shares and purchased 3,158,142 voting common shares and 2,380,608 nonvoting common shares of Saxon pursuant to an equity participation agreement. These transactions increased Forest's economic interest in Saxon to 66%.
On January 31, 1996 the Company completed the acquisition of ATCOR Resources Ltd. of Calgary, Alberta for approximately $136,000,000, including acquisition costs of approximately $1,000,000. The purchase was funded by the net proceeds of a Common Stock offering and approximately $8,300,000 drawn under the Company's bank credit facility. The exploration and production business of ATCOR was renamed Canadian Forest Oil Ltd. (Canadian Forest). Canadian Forest's principal reserves and producing properties are located in Alberta and British Columbia, Canada. As part of the Canadian Forest acquisition, Forest also acquired ATCOR's natural gas marketing business which was renamed Producers Marketing Ltd. (ProMark).
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(2) ACQUISITIONS (CONTINUED): - -------------------------------------------------------------------------------
The consolidated balance sheet of Forest includes the accounts of Saxon and Canadian Forest at December 31, 1996. The consolidated statements of operations include the results of operations of Saxon effective January 1, 1996 and the results of operations of Canadian Forest effective February 1, 1996. The following unaudited pro forma consolidated statements of operations information assumes that the Common Stock offering and the acquisitions of Saxon and Canadian Forest occurred as of January 1, 1995:
Pro Forma Year Ended December 31, --------------------------------- 1996 1995 ---- ---- (In Thousands Excluding Per Share Amounts)
Revenue: Marketing and processing $ 200,715 139,444 Oil and gas sales 132,423 129,326 Miscellaneous, net 1,387 132 --------- ------- Total revenue $ 334,525 268,902 --------- ------- --------- -------
Earnings (loss) before income taxes, and extraordinary item $ 7,512 (9,680) --------- ------- --------- -------
Net earnings (loss) $ 3,687 (15,972) --------- ------- --------- -------
Primary earnings (loss) per share $ .06 (.81) --------- -------- --------- --------
Fully diluted earnings (loss) per share $ .05 (.81) --------- -------- --------- --------
(3) ANSCHUTZ AND JEDI TRANSACTIONS: - -----------------------------------------------------------------------------
During 1995 and 1996, the Company consummated transactions with The Anschutz Corporation (Anschutz) and with Joint Energy Development Investments Limited Partnership (JEDI), a Delaware limited partnership the general partner of which is an affiliate of Enron Corp. (Enron).
Pursuant to a purchase agreement between the Company and Anschutz, Anschutz Purchased 3,760,000 shares of the Company's Common Stock and 620,000 shares of a new series of preferred stock which were convertible into 1,240,000 additional shares of Common Stock for a total consideration of $45,000,000. The preferred stock had a liquidation preference of $18.00 per share and received dividends ratably with the Common Stock. In addition, Anschutz received a warrant that entitled it to purchase 3,888,888 shares of the Company's Common Stock for $10.50 per share (the A Warrant). The A Warrant was scheduled to expire July 27, 1998.
The Anschutz investment was made in two closings. At the first closing, which occurred on May 19, 1995, Anschutz loaned the Company $9,900,000. The loan carried interest at 8% per annum. The loan was nonrecourse to the company and was secured by oil and gas properties owned by the Company, the preferred stock of Archean Energy Ltd., and a cash collateral account with an initial balance of $2,000,000. At the second closing, which occurred in July 1995, Anschutz converted the loan into 1,100,000 shares of Common Stock and the shares issued were recorded at the carrying amount of the loan ($9,900,000). At the second closing, Anschutz purchased an additional 2,660,000 shares of Common Stock, the convertible preferred stock and the A Warrant for $35,100,000. The total proceeds received by the Company at the second closing were allocated based on the relative fair market values of the Common Stock ($18,272,000), convertible preferred stock ($8,518,000) and the A Warrant ($8,310,000) issued. The Company also entered into a shareholders agreement with Anschutz pursuant to which Anschutz agreed to certain voting, acquisition, and transfer limitations regarding its shares of Common Stock for five years after the second closing.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(3) ANSCHUTZ AND JEDI TRANSACTIONS (CONTINUED): - -------------------------------------------------------------------------------
At the second closing on July 27, 1995, Forest and JEDI restructured JEDI'S existing loan which had a principal balance of approximately $62,368,000 before unamortized discount of $4,984,000. As a part of the restructuring, the existing JEDI loan balance was divided into two tranches: A $40,000,000 tranche, which bore interest at the rate of 12.5% per annum and was due and payable in full on December 31, 2000; and an approximately $22,400,000 tranche, which did not bear interest and was due and payable in full on December 31, 2002. JEDI also relinquished the net profits interest that it held in certain properties of the Company. In consideration, JEDI received a warrant (the B Warrant) that entitled it to purchase 2,250,000 shares of the Company's Common Stock for $10.00 per share. The B Warrant was recorded at its estimated fair value. The fair value of the B Warrant was estimated to be approximately $12,100,000, representing the amount determined using the Black-Scholes Option Pricing Model, based on the market value of the stock at the date of the transaction, less a discount of 10% to reflect the size of the block of shares to be issued and the estimated brokerage fees on the ultimate disposition of the shares.
Also at the second closing, JEDI granted an option to Anschutz (the Anschutz Option), pursuant to which Anschutz was entitled to purchase from JEDI up to 2,250,000 shares of the Company's Common Stock at a purchase price per share equal to the lesser of (a) $10.00 plus 18% per annum from July 27, 1995 to the date of exercise of the option, or (b) $15.50. The Anschutz Option was scheduled to terminate on July 27, 1998. JEDI was to satisfy its obligations under the Anschutz Option by exercising the B Warrant. The Company also agreed to use the proceeds from the exercise of the A Warrant to pay principal and interest on the $40,000,000 tranche of the JEDI loan.
As a result of the loan restructuring and the issuance of the B Warrant, the Company reduced the recorded amount of the related liability to approximately $45,493,000. No gain or loss was recorded on the loan restructuring since the estimated fair value of the restructured loan and the B Warrant was approximately equal to the original loan balance.
In December 1995, JEDI exchanged the $22,400,000 tranche and the B Warrant for 1,680,000 shares of Common Stock (the JEDI Exchange). The fair value of the 1,680,000 shares of Common Stock was estimated to be $15,400,000 based on the quoted market price of the Common Stock at the date of the transaction, less a discount of 35% to reflect the shareholder agreement with JEDI that limited JEDI's ability to vote the shares or to transfer the shares before July 27, 1998, the size of the block of stock and the estimated brokerage fees on the ultimate disposition of the shares. No gain or loss was recorded on the exchange since the estimated fair value of the Common Stock issued less the estimated fair value of the B warrant reacquired was approximately equal to the carrying amount of the $22,400,000 tranche.
Pursuant to the JEDI Exchange, the Company assumed JEDI's obligations under the Anschutz Option. Under the Anschutz Option, the Company was then obligated to issue shares directly to Anschutz that previously would have been issued to JEDI pursuant to the B Warrant.
On August 1, 1996 the Anschutz Corporation exercised the Anschutz Option to purchase 2,250,000 shares of Common Stock for $26,200,000 or approximately $11.64 per share. Proceeds received by Forest were used primarily to fund a portion of 1996 capital expenditures.
On November 5, 1996 the Company exchanged 2,000,000 shares of Common Stock plus approximately $13,500,000 cash to extinguish approximately $43,000,000 of nonrecourse secured debt then owed to JEDI. In connection with this transaction, Anschutz acquired 1,628,888 shares of Common Stock by exercising a portion of the A Warrant to purchase 388,888 shares of Common Stock at $10.50 per share and by converting 620,000 shares of Forest's Second Series Preferred Stock into 1,240,000 shares of Common Stock. The term of the remaining 3,500,000 warrants held by Anschutz was extended to July 27, 1999. The fair value of the shares of Common Stock issued to JEDI was estimated based on the quoted market price of the Common Stock at the date of the transaction, less a discount of 7-1/2% to reflect the lock-up agreement with JEDI that limited JEDI's ability to transfer the shares before May 31, 1997, the size of the block of shares to be issued and the estimated brokerage fees on the ultimate disposition of the shares. The fair value of the Common Stock issued and the cash paid to JEDI, including
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(3) ANSCHUTZ AND JEDI TRANSACTIONS (CONTINUED): - -------------------------------------------------------------------------------
related expenses of the transaction, was less than the carrying amount of the debt extinguished. Accordingly, the Company recorded an extraordinary gain on extinguishment of debt in the fourth quarter of 1996 of approximately $2,166,000.
(4) INVESTMENT IN AFFILIATE: - -------------------------------------------------------------------------------
In 1992, the Company sold its Canadian assets and related operations to CanEagle resources corporation (CanEagle) for approximately $51,250,000 in Canadian funds ($41,000,000 U.S.). In the transaction, the Company received cash of approximately $28,000,000 CDN ($22,400,000 U.S.), net of expenses, and provided financing in the aggregate principal amount of $22,000,000 CDN ($17,600,000 U.S.). On June 24, 1994 CanEagle sold a significant portion of its oil and gas properties to a third party. In conjunction with this transaction, the Company received $6,124,000 CDN ($4,400,000 U.S.) and exchanged its investment in CanEagle for shares of preferred stock of a newly formed entity, Archean Energy, Ltd. (Archean). The Company accounted for the proceeds from the 1992 and 1994 transactions as reductions in the carrying value of its investment in CanEagle. The preferred shares of Archean were recorded at an amount equal to the remaining carrying value of the Company's investment in CanEagle.
The Company accounted for its investment in Archean (and CanEagle prior to June 24, 1994) in a manner analagous to equity accounting. Losses were recognized to the extent that losses were attributable to the Company's interest. Earnings were recognized only if realization was assured. Under this method, no earnings or losses were recognized in 1996, 1995 or 1994.
In December 1995, in connection with the Saxon acquisition, the Company transferred its Archean preferred stock to Saxon and the Company continued to account for the investment in Archean at its historical carrying value. In September 1996, the preferred shares of Archean were redeemed for cash at their approximate carrying value.
(5) LONG-TERM DEBT: - -------------------------------------------------------------------------------
Long-term debt at December 31 consists of the following:
1996 1995 ---- ---- Credit facility $ 26,400 23,800 Canadian Forest credit facility 32,500 - Saxon credit facility - 16,437 Nonrecourse secured loan - 40,322 Production payment obligation 12,596 16,218 11-1/4% Senior Subordinated Notes 99,421 99,365 -------- -------- 170,917 196,142 Less current portion (2,058) (2,263) -------- --------
Long-term debt $168,859 193,879 -------- -------- -------- --------
CREDIT FACILITY: The Company has a secured credit facility (the Credit Facility) with The Chase Manhattan Bank, NA. (Chase) as agent for a group of banks. Under the Credit Facility, as amended, the Company may borrow up to $60,000,000 for working capital and/or general corporate purposes. Advances under this facility bear interest at rates ranging from the banks' prime rate to prime plus 3/4% or, alternatively, the London interbank offered rate (LIBOR) plus 1.0% to LIBOR plus 1 3/4% depending on the ratio of debt to total capitalization for the Company. The borrowing base is subject to formal redetermination semi-annually, but may be changed at the banks' discretion at any time.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(5) LONG-TERM DEBT (CONTINUED): - -------------------------------------------------------------------------------
The Credit Facility is secured by a lien on, and a security interest in, a majority of the Company's domestic proved oil and gas properties and related assets (subject to prior security interests granted to holders of volumetric production payment agreements) and a pledge of accounts receivable. The maturity date of the Credit Facility is January 31, 2000. Under the terms of the Credit Facility, the Company is subject to certain covenants and financial tests, including restrictions or requirements with respect to working capital, cash flow, additional debt, liens, asset sales, investments, mergers, cash dividends on capital stock and reporting responsibilities. At December 31, 1996 notes payable of $26,400,000 were outstanding under the Credit Facility with interest at rates ranging from 7.00% to 8.75% per annum. The Company has also used the Credit Facility for a $1,500,000 letter of credit.
CANADIAN FOREST CREDIT FACILITY: On February 8, 1996 a newly-formed Canadian subsidiary of Forest entered into a credit agreement (the Canadian Credit Facility) with The Chase Manhattan Bank of Canada for the benefit of Canadian Forest and ProMark. The borrowing base under the Canadian Credit Facility is $60,000,000 CDN. The borrowing base is subject to formal redeterminations semi-annually, but may be changed by the bank at its discretion at any time. The maturity date of the Canadian Credit Facility is February 7, 1999. The Canadian Credit Facility is indirectly secured by substantially all the assets of Canadian Forest. Funds drawn under the Canadian Credit Facility can be used for general corporate purposes. Under the terms of the Canadian Credit Facility, the three Canadian subsidiaries are subject to certain covenants and financial tests including restrictions or requirements with respect to working capital, cash flow, additional debt, liens, asset sales, investments, mergers, cash dividends and reporting responsibilities. At December 31, 1996 the outstanding balance under this facility was $32,500,000 (US) with interest at rates ranging from 7.25% to 7.3125% per annum. Canadian Forest has entered into interest rate swaps which fix the interest rate on approximately $22,000,000 of long-term debt at 10.055% to 10.55% with terms expiring in 1998. The Company has also used this facility for a letter of credit in the amount of $3,081,000 CDN.
SAXON CREDIT FACILITY: Saxon has a revolving credit facility with a borrowing base of $20,000,000 CDN. The loan is subject to semi-annual review and has demand features; however, repayments are not required provided that borrowings are not in excess of the borrowing base and Saxon complies with other existing covenants. At December 31, 1996 there was no outstanding balance under this facility.
NONRECOURSE SECURED LOAN: On December 30, 1993, the Company entered into a nonrecourse secured loan agreement with JEDI. the terms of the JEDI loan were restructured in 1995 as described in Note 3. Under the terms of the restructured JEDI loan, the Company was required to make payments based on the net proceeds, as defined, from certain subject properties. Payments under the JEDI loan were due monthly and were equal to 90% of total net operating income from the secured properties, reduced by 80% of allowable capital expenditures, as defined. On November 5, 1996 the Company exchanged 2,000,000 shares of Common Stock plus approximately $13,500,000 cash to extinguish the remaining balance of the nonrecourse secured debt owed to JEDI of approximately $43,000,000. See Note 3.
PRODUCTION PAYMENT OBLIGATION: The dollar-denominated production payment was entered into in 1992 to finance property acquisitions. 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, 1996 the remaining principal amount was $16,981,000 and the recorded liability was $12,596,000. Under the terms of this production payment, the Company must make a monthly cash payment which is the greater of a base amount or 85% of net proceeds from the subject properties located in the United States, as defined, except that the amount required to be paid in any given month shall not exceed 100% of the net proceeds from the subject properties. The Company retains a management fee equal to 10% of sales from the properties, which is deducted in the calculation of net proceeds. The Company's current estimate, based on expected production and prices, budgeted capital expenditure levels and expected discount amortization, is that 1997 payments will reduce the recorded liability by approximately $2,058,000, which amount is included in current liabilities, increase the recorded liability by
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(5) LONG-TERM DEBT (CONTINUED): - -------------------------------------------------------------------------------
approximately $1,022,000 in 1998, and reduce the recorded liability by $975,000 in 1999, $2,433,000 in 2000 and $2,038,000 in 2001. Properties to which approximately 3% of the Company's estimated proved reserves are attributable, on an mcfe basis, are dedicated to this production payment financing.
11-1/4% SENIOR SUBORDINATED NOTES: 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 Senior Subordinated Notes are redeemable at the option of the Company, in whole or in part, at any time on or after September 1, 1998 initially at a redemption price of 105.688%, plus accrued interest to the date of redemption, declining at the rate of 1.896% per year to September 1, 2000 and at 100% thereafter.
Under the terms of the Senior Subordinated Notes, the Company must meet certain tests before it is able to pay cash dividends 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 Subordinated Notes also limit the Company's ability to undertake a consolidation, merger or transfer of all or substantially all of its assets. In addition, the Company is, subject to certain conditions, obligated to offer to repurchase Senior Subordinated Notes at par value plus accrued and unpaid interest to the date of repurchase, with the net cash proceeds of certain sales or dispositions of assets. Upon a change of control, as defined, the Company will be required to make an offer to purchase the Senior Subordinated Notes at 101% of the principal amount thereof, plus accrued interest to the date of purchase.
(6) DEFERRED REVENUE: - --------------------------------------------------------------------------------
From April 1991 through July 1994, the Company entered into various volumetric production payments with entities affiliated with Enron for net proceeds of $139,058,000. Under the terms of these production payments, the Company was required to deliver 80.1 BCF of natural gas and 770,000 barrels of oil over periods ranging from three to eight years.
The Company is required to deliver the scheduled volumes from the subject properties or to make a cash payment for volumes produced but not delivered, in combination not to exceed a specified percentage of monthly production. If production levels are not sufficient to meet scheduled delivery commitments, the Company must account for and make up such shortages, at market-based prices, from future production.
The Company is responsible for royalties and for production costs associated with operating the properties subject to the production payment agreements. The Company may grant liens on properties subject to the production payment agreements, but it must notify prospective lienholders that their rights are subject to the prior rights of the production payment owner.
Amounts received under the production payments were recorded as deferred revenue. Volumes associated with amortization of deferred revenue for the years ended December 31, 1996, 1995 and 1994 were as follows:
Net sales volumes attributable to production Volumes delivered (1) payment deliveries (2) ----------------------------- -------------------------- Natural Gas Oil Natural Gas Oil (MMCF) (MBBLS) (MMCF) (MBBLS) ----------- ------- --------- ------- 1996 3,721 87 3,168 74 1995 11,045 173 9,120 145 1994 19,985 218 16,005 182
(1) Amounts settled in cash in lieu of volumes were $1,641,000, $2,433,000 and $5,742,000 for the years ended December 31, 1996, 1995, and 1994, respectively. (2) Represents volumes required to be delivered to Enron affiliates net of estimated royalty volumes.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(6) DEFERRED REVENUE (CONTINUED): - --------------------------------------------------------------------------------
Future amortization of deferred revenue, based on the scheduled deliveries under the production payment agreements, is as follows:
(1) Represents volumes required to be delivered to Enron net of estimated royalty volumes.
(7) INCOME TAXES: - --------------------------------------------------------------------------------
The income tax expense (benefit) is different from amounts computed by applying the statutory Federal income tax rate for the following reasons:
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(7) INCOME TAXES (CONTINUED): - -------------------------------------------------------------------------------
Deferred income taxes generally result from recognizing income and expenses at different times for financial and tax reporting. In the U.S., differences result in part from capitalization of certain development, exploration and other costs under the full cost method of accounting, recording proceeds from the sale of properties in the full cost pool, and the provision for impairment of oil and gas properties for financial accounting purposes. In Canada, differences result in part from accelerated cost recovery of oil and gas capital expenditures for tax purposes.
The components of the net deferred tax liability at December 31, 1996 and 1995 are as follows:
1996 1995 ---- ---- (In Thousands) Deferred tax assets: Allowance for doubtful accounts $ 296 283 Accrual for retirement benefits 1,128 1,223 Accrual for medical benefits 2,220 2,220 Accrual for sales recorded on the entitlement method 1,499 2,920 Accrual for interest rates swaps 509 - Net operating loss carryforward 46,828 39,264 Depletion carryforward 6,958 6,958 Investment tax credit carryforward 2,576 3,219 Alternative minimum tax credit carryforward 2,187 2,187 Other 613 243 --------- -------- Total gross deferred tax assets 64,814 58,517 Less valuation allowance (43,999) (45,124) --------- -------- Net deferred tax assets 20,815 13,393
Deferred tax liabilities: Property and equipment (48,475) (13,393) Deferred income on long term contracts (6,014) - Other (42) - --------- --------
Total gross deferred tax liabilities (54,531) (13,393) --------- -------- Net deferred tax liability $(33,716) - --------- -------- --------- --------
The net change in the total valuation allowance for the year ended December 31, 1996 was a decrease of $1,125,000, which includes a decrease in the valuation allowance of $758,000 attributable to the extraordinary gain.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(7) INCOME TAXES (CONTINUED): - --------------------------------------------------------------------------------
The Alternative Minimum Tax (AMT) credit carryforward available to reduce future U.S. Federal regular taxes aggregated $2,187,000 at December 31, 1996. this amount may be carried forward indefinitely. U.S. Federal regular and amt net operating loss carryforwards at December 31, 1996 were $133,795,000 and $130,142,000, respectively, and will expire in the years indicated below:
Regular AMT ------- --- (In Thousands)
2000 $ 3,590 4,975 2005 8,307 - 2008 28,999 31,799 2009 22,817 22,964 2010 45,736 46,058 2011 24,346 24,346 -------- -------- $133,795 130,142 -------- -------- -------- --------
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 U.S. Federal income taxes aggregated $2,576,000 at December 31, 1996 and expire at various dates through the year 2001. Percentage depletion carryforwards available to reduce future U.S. Federal taxable income aggregated $19,879,000 at December 31, 1996. This amount may be carried forward indefinitely.
Canadian tax pools available to reduce future Canadian Federal income taxes aggregated approximately $78,000,000 at December 31, 1996. These tax pool balances are deductible on a declining balance basis ranging from ten to one hundred percent of the balance annually. These amounts may be carried forward indefinitely.
The availability of some of these U.S. Federal tax attributes to reduce current and future U.S. 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 limited due to the occurrence of an "ownership change" within the meaning of Section 382 of the Internal Revenue Code resulting from the Anschutz transaction in 1995 and the public stock issuance in 1996. under the general provisions of Section 382 of the code, the Company's net operating loss carryforwards will be subject to an annual limitation as to their use of approximately $5,700,000. Even though the Company is limited in its ability to use the net operating loss carryovers under these 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 their 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 has not finalized its calculation of the amount of built-in gains at the date of the ownership change, but estimates that its ability to fully utilize its net operating loss carryforwards may be limited by these provisions.
Due to limitations in the Internal Revenue Code, other than the Section 382 limitations discussed above, the Company believes it is unlikely that it will be able to use any significant portion of its investment tax credit carryforwards before they expire.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(8) PREFERRED STOCK: - -------------------------------------------------------------------------------
$.75 CONVERTIBLE PREFERRED STOCK: The Company had 10,000,000 shares of $.75 Convertible Preferred Stock authorized, par value $.01 per share, of which there were 2,877,673 shares outstanding at December 31, 1996 and 2,880,173 shares outstanding at December 31, 1995, with an aggregate liquidation preference of $28,776,730 at December 31, 1996 and $28,801,730 at December 31, 1995. This stock was convertible at any time, at the option of the holder, at the rate of .7 shares of Common Stock for each share of $.75 Convertible Preferred Stock, subject to adjustment upon occurrence of certain events. During 1996, 2,500 shares of $.75 Convertible Preferred Stock were converted into 1,750 shares of Common Stock; during 1995, 800 shares of $.75 Convertible Preferred Stock were converted into 560 shares of Common Stock; there were no conversions in 1994. The $.75 Convertible Preferred Stock was redeemable, in whole or in part, at the option of the Company, after July 1, 1996 at $10.00 per share plus accumulated and unpaid dividends. Cumulative annual dividends of $.75 per share were payable quarterly, in arrears, on the first day of February, May, August and November, when and as declared. Until December 31, 1993, the Company was required to pay such dividends in shares of Common Stock. After such date, dividends could be paid in cash or, at the Company's election, in shares of Common Stock or in a combination of cash and Common Stock; however, the Company was prohibited from paying cash dividends on its $.75 Convertible Preferred Stock from the February 1, 1995 dividend through the March 8, 1996 dividend due to restrictions contained in the Credit Facility with its lending banks. After such date, dividends could be paid in cash or at the Company's election, in shares of Common Stock or in a combination of cash and Common Stock. Under the terms of the $.75 Convertible Preferred Stock, Common Stock delivered in payment of dividends was valued for dividend payment purposes at between 75% and 90%, depending on trading volume, of the average last reported sales price of the Common Stock during a specified period prior to the record date for the dividend payment. During any period in which dividends on preferred stock were in arrears, no dividends or distributions, except for dividends paid in shares of Common Stock, could be paid or declared on the Common Stock, nor could any shares of Common Stock be acquired by the Company.
The Company called for redemption on February 28, 1997 all 2,877,673 shares of its $.75 Convertible Preferred Stock. The redemption price was $10.00 per share plus accumulated and unpaid dividends to and including the date of redemption (for an aggregate redemption price of $10.06 per share). In lieu of cash redemption, prior to the close of business on February 21, 1997 the holders of the preferred shares had the right to convert each share into 0.7 share of Forest's Common Stock. As of February 21, 1997 2,783,945 shares or 96.7% of the shares outstanding were tendered for conversion into Common Stock. The remaining 93,728 shares that were not tendered for conversion were redeemed by the Company at the redemption price of $10.06 per share on February 28, 1997.
SECOND SERIES PREFERRED STOCK: At December 31, 1995 the Company had 620,000 shares of Second Series Preferred Stock authorized, par value $.01 per share, of which there were 620,000 shares outstanding, with an aggregate liquidation preference of $11,160,000. Each share of Second Series Preferred Stock (1) was convertible into 2 shares of Common Stock, (2) had no right to vote, (3) had the right to receive dividends on the dates and in the form that dividends were payable on the Common Stock, and (4) had the right, upon any liquidation, dissolution or winding up of the Company, before any distribution is made on any shares of Common Stock, to be paid the amount of $18.00 and, after there shall have been paid to each share of Common Stock the amount of $9.00, had the right to receive distributions on the dates and in the form that distributions are payable on the Common Stock. On November 5, 1996 all 620,000 shares of the Company's Second Series Preferred Stock were converted into 1,240,000 shares of Common Stock.
(9) COMMON STOCK:
COMMON STOCK: The Company has 200,000,000 shares of Common Stock authorized, par value $.10 per share. On January 5, 1996 a 5-to-1 reverse stock split was approved by the Company's shareholders. The reverse split became effective on January 8, 1996. unless otherwise indicated, all share amounts have been adjusted to give effect to the 5-to-1 reverse stock split.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(9) COMMON STOCK (CONTINUED): - -------------------------------------------------------------------------------
On January 31, 1996 13,200,000 shares of Common Stock were sold for $11.00 per share in a public offering. Of this amount 1,060,000 shares were sold by Saxon and 12,140,000 were sold by Forest. The net proceeds to Forest and Saxon from the issuance of shares totaled approximately $136,000,000 after deducting issuance costs and underwriting fees.
In October 1993, the Board of Directors adopted a shareholders' rights plan (the Plan) and entered into the rights agreement. The Company paid a dividend distribution of one Preferred Share Purchase Right (the Rights) 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. In connection with the Anschutz transaction, the Company amended the Rights Agreement to exempt from the provisions of the Rights Agreement shares of Common Stock acquired by Anschutz and JEDI in the Anschutz and JEDI transactions, including shares later acquired pursuant to the conversion of the Second Series Preferred Stock or the exercise of the A Warrant and the Anschutz option. The amendment to the Rights Agreement did not exempt other shares of Common Stock acquired by Anschutz or JEDI from the provisions of the Rights Agreement.
WARRANTS: At December 31, 1995 the Company had outstanding 1,244,715 warrants to purchase shares of its Common Stock (the public warrants). Each Public Warrant entitled the holder to purchase one-fifth share of Common Stock at a price of $3.00 and was noncallable. During 1996, 112,185 warrants were exercised to purchase 22,437 shares of Common Stock. On October 1, 1996 the remaining Public Warrants expired.
In December 1995, the Company assumed JEDI's obligations under the Anschutz Option. On August 1, 1996 Anschutz exercised the Anschutz Option for $26,200,000 or approximately $11.64 per share and Anschutz received 2,250,000 shares of Common Stock.
At December 31, 1996 the Company has outstanding the A Warrant that is held by Anschutz. At that date, the A Warrant entitled the holder to purchase 3,500,000 shares of Common Stock at a price of $10.50 per share. The Warrant expires on July 27, 1999. On November 5, 1996 Anschutz exercised a portion of the A Warrant and purchased 388,888 shares of Common Stock at $10.50 per share.
STOCK OPTIONS: In March 1992, the Company adopted the 1992 Stock Option Plan under which non-qualified stock options may be granted to key employees and non-employee directors. The aggregate number of shares of Common Stock which the Company may issue under options granted pursuant to this plan may not exceed 10% of the total number of shares outstanding or issuable at the date of grant pursuant to outstanding rights, warrants, convertible or exchangeable securities or other options. The exercise price of an option may not be less than 85% of the fair market value of one share of the Company's Common Stock on the date of grant. The options vest 20% on the date of grant and an additional 20% on each grant anniversary date thereafter.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(9) COMMON STOCK (CONTINUED): - -------------------------------------------------------------------------------
The following table summarizes the activity in the Company's stock-based compensation plan for the years ended December 31, 1994, 1995 and 1996:
Weighted Average Number of Number of Exercise Shares Shares Price Exercisable --------- -------- ----------- Outstanding at December 31, 1993 610,800 $ 19.99 155,320 Granted at fair value 62,000 25.00 Exercised (7,000) 15.00 Cancelled (7,000) 25.00 --------- -------- Outstanding at December 31, 1994 658,800 20.46 372,080 Cancelled (30,800) 20.52 --------- -------- Outstanding at December 31, 1995 628,000 20.46 461,200 Granted at fair value 1,383,900 12.74 Exercised (35,120) 11.42 Cancelled (515,200) 20.47 --------- -------- Outstanding at December 31, 1996 1,461,580 $ 13.37 362,460 --------- -------- --------- --------
The fair value of each option granted in 1996 was estimated using the Black-Scholes option pricing model with the following assumptions: expected option life of 5 years; risk free interest rates ranging from 5.261% to 6.022%; estimated volatility of 59.95%; and dividend yield of zero percent. The weighted average fair market value of options granted during 1996 was estimated to be $7.22 per share based on these assumptions.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(9) COMMON STOCK (CONTINUED): - --------------------------------------------------------------------------------
The following table summarizes information about options outstanding at December 31, 1996:
Options Outstanding Options Excercisable ---------------------------------- --------------------- Weighted Average Weighted Weighted Remaining Average Average Range of Number of Contractual Exercise Number of Exercise Exercise Price Shares Life Price Shares Price -------------- --------- ----------- -------- --------- --------- $11.25-12.63 666,080 9.23 $11.53 107,360 $11.59 $14.00-15.00 737,500 9.45 14.17 197,100 14.34 $25.00 58,000 5.75 25.00 58,000 25.00 ------------ --------- ---- ------ ------- ------ $11.25-25.00 1,461,580 9.20 $13.37 362,460 $15.23 ------------ --------- ---- ------ ------- ------ ------------ --------- ---- ------ ------- ------
The Company applies APB Opinion 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost is recognized for options granted at a price equal to the fair market value of the common stock. Had compensation cost for the Company's stock-based compensation plan been determined using the fair value of the options at the grant date, the Company's net income for the year ended December 31, 1996 would have been $2,230,000 and net earnings per share would have been less than $.01 per share. There were no stock options granted in 1995; accordingly, no compensation cost would have been recognized in that year.
(10) EMPLOYEE BENEFITS - --------------------------------------------------------------------------------
PENSION PLANS: The Company has a qualified defined benefit pension plan which covers its U.S. employees (Pension Plan). The Pension Plan has been curtailed and all benefit accruals were suspended effective May 31, 1991.
The benefits under the Pension Plan are based on years of service and the employee's average compensation during the highest consecutive sixty-month period in the fifteen years prior to retirement. No contribution was made to the Plan in 1996, 1995 or 1994.
The following table sets forth the Pension Plan's funded status and amounts recognized in the Company's consolidated financial statements at December 31:
1996 1995 -------- -------- (In Thousands)
Actuarial present value of accumulated benefit obligation (all benefits are vested) $(25,959) $(27,485) -------- -------- -------- -------- Projected benefit obligation for service rendered to date $(25,959) $(27,485) Plan assets at fair market value, consisting primarily of listed stocks, bonds and other fixed income obligations 24,897 24,270 -------- -------- Unfunded pension liability (1,062) (3,215) Unrecognized net loss from past experience different from that assumed and effects of changes in assumptions 2,012 4,133 -------- -------- Pension asset recognized in the balance sheet $ 950 $ 918 -------- -------- -------- --------
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED): - --------------------------------------------------------------------------------
For 1996, the discount rate used in determining the actuarial present value of the projected benefit obligation was 7.75% and the expected long-term rate of return on assets was 9%. For 1995, the discount rate used in determining the actuarial present value of the projected benefit obligation was 7.25% and the expected long-term rate of return on assets was 9%. For 1994 the discount rate used in determining the actuarial present value of the projected benefit obligation was 9% and the expected long-term rate of return on assets was 9%.
The components of net pension expense (benefit) for the years ended December 31, 1996, 1995 and 1994 are as follows:
1996 1995 1994 ------- ------- ------- (In Thousands) Net pension expense (benefit) included the following components: Interest cost on projected benefit obligation $ 1,926 $ 2,049 $ 1,976 Actual return on plan assets (3,056) (3,243) (245) Net amortization and deferral 1,098 1,234 (1,955) ------- ------- ------- Net pension expense (benefit) $ (32) $ 40 $ (224) ------- ------- ------- ------- ------- -------
The Company has a non-qualified unfunded supplementary retirement plan that provides certain officers with defined retirement benefits in excess of qualified plan limits imposed by Federal tax law. Benefit accruals under this plan were suspended effective May 31, 1991 in connection with suspension of benefit accruals under the Pension Plan. At December 31, 1996 the projected benefit obligation under this plan totaled $604,000, which amount is included in other liabilities in the accompanying balance sheet. The projected benefit obligation is determined using the same discount rate as is used for calculations for the Pension Plan.
In 1993, as a result of the change in the discount rate for the Pension Plan and the supplementary retirement plan, the Company recorded a liability of $3,038,000, representing the unfunded pension liability, and a corresponding decrease in capital surplus. As a result of changes in the discount rate for the Pension Plan and the supplementary retirement plan, the Company records corresponding changes in the liability and capital surplus. In 1994, the Company reduced the liability representing the unfunded pension liability by approximately $1,570,000, with a corresponding increase in capital surplus. In 1995, the Company increased the unfunded pension liability by approximately $2,836,000, with a corresponding decrease in capital surplus. In 1996, the Company reduced the unfunded pension liability by approximately $2,145,000, with a corresponding increase in capital surplus.
Canadian Forest's employees are members of a non-contributory defined benefit pension plan (Canadian Pension Plan). The benefits under the Canadian Pension Plan are based on years of service, the employee's average annual compensation during the highest consecutive sixty month period of pensionable service and the employee's age at retirement. Canadian Forest's contribution to the Canadian Pension Plan was $47,000 in 1996.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED): - --------------------------------------------------------------------------------
The following table sets forth the Canadian Pension Plan's funded status and amounts recognized in the Company's consolidated financial statements at December 31:
-------------- (In Thousands)
Actuarial present value of accumulated benefit obligation (all benefits are vested) $(4,119) ------- ------- Projected benefit obligation for service rendered to date $(4,119) Plan assets at fair market value, consisting primarily of listed stocks, bonds and other fixed income obligations 4,922 ------- Pension surplus 803 Unrecognized net gain from past experience different from that assumed and effects of changes in assumptions (915) ------- Pension liability recognized in the balance sheet $ (112) ------- -------
For 1996, the discount rate used in determining the actuarial present value of the projected benefit obligation was 7% and the expected long-term rate of return on assets was 7%.
The components of net pension expense for the year ended December 31 is as follows:
-------------- (In Thousands)
Net pension expense included the following components: Interest cost on projected benefit obligation $ 456 Actual return on plan assets (310) Net amortization and deferral (69) ------- Net pension expense $ 77 ------- -------
RETIREMENT SAVINGS PLANS: The Company sponsors a qualified tax deferred savings plan in accordance with the provisions of Section 401(k) of the Internal Revenue Code for its U.S. employees. 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 the first six months of 1995 and in 1994, Company contributions were made using treasury stock. In the last six months of 1995 and in the first nine months of 1996, Company contributions were made by issuing authorized but unissued shares of Common Stock. In the last three months of 1996, Company contributions were made in cash. The expense associated with the Company's contribution was $399,000 in 1996, $423,000 in 1995 and $516,000 in 1994.
Canadian Forest also provides a savings plan which is available to all of its employees. Employees may contribute up to 4% of their salary, subject to certain limitations, with Canadian Forest matching the employee contribution in full. Certain limitations are in effect with respect to withdrawals from the plan. Canadian Forest's contribution to the plan was $95,000 in 1996.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED): - --------------------------------------------------------------------------------
EXECUTIVE RETIREMENT AGREEMENTS: The Company entered into agreements in December 1990 (the Agreements) with certain former 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 also continued to participate in the Company's royalty bonus program until December 31, 1995. The Company has also agreed to maintain certain life insurance policies in effect at December 1990, for the benefit of each of the Retirees.
The Company's obligation to one retiree under a revised retirement agreement is payable in Common Stock or cash, at the Company's option, in May of each year from 1993 through 1996 at approximately $190,000 per year with the balance of $149,000 payable in May 1997. The Agreements for the other six Retirees provide for supplemental retirement payments totaling approximately $970,000 per year through 1998 and approximately $770,000 per year in 1999 and 2000.
The $2,881,000 present value of the amounts due under the agreements, discounted at 13%, is included in other current and long-term liabilities.
LIFE INSURANCE: The Company provides life insurance benefits for certain key employees and retirees under split dollar life insurance plans. the premiums for the life insurance policies were $921,000, $921,000 and $916,000 in 1996, 1995 and 1994, respectively, including $831,000 in each of the years 1996, 1995 and 1994 for policies for retired executives. Under the life insurance plans, the Company is assigned a portion of the benefits which is designed to recover the premiums paid.
POSTRETIREMENT BENEFITS: The Company accrues expected costs of providing postretirement benefits to employees, their beneficiaries and covered dependents in accordance with Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," (SFAS No. 106).
The following table sets forth the status of the postretirement benefit plan and the amounts recognized in the Company's consolidated financial statements at December 31:
1996 1995 ------ ------ (In Thousands)
Retired participants $4,522 $4,803 Active participants fully eligible for benefits 256 201 Other active participants 1,101 1,026 ------ ------ Accumulated postretirement benefit obligation (APBO) 5,879 6,030
Plan assets at fair market value - - ------ ------ APBO in excess of plan assets 5,879 6,030 Unrecognized loss (166) (595) ------ ------ Accrued postretirement benefit liability $5,713 $5,435 ------ ------ ------ ------
The discount rates used in determining the actuarial present value of the APBO at December 31, 1996, 1995 and 1994 were 7.75%, 7.25% and 9%, respectively.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED): - --------------------------------------------------------------------------------
The components of postretirement benefit expense for the years ended December 31, 1996, 1995 and 1994 are as follows:
1996 1995 1994 ---- ---- ---- (In Thousands) Service cost $131 $ 83 $103 Interest cost on APBO 418 421 407 ---- ---- ---- Postretirement benefit cost $549 $504 $510 ---- ---- ---- ---- ---- ----
For 1996, a 1% increase in health care cost trends would have increased the APBO by $723,000 and the service and interest cost by $84,000.
(11) RELATED PARTY TRANSACTIONS: - --------------------------------------------------------------------------------
Prior to 1995, the Company used a real estate complex (the Complex) owned directly or indirectly by certain stockholders and members of the Board of Directors for Company-sponsored seminars, the accommodation of business guests, the housing of personnel attending corporate meetings and for other general business purposes. In 1994, in connection with the Company's termination of usage, the company paid $662,000 on account of the business use of such property, and an additional $300,000 as a partial reimbursement of deferred maintenance costs.
John F. Dorn resigned as an executive officer and director of the Company in 1993. The Company agreed to pay Mr. Dorn his salary at the time of his resignation through September 30, 1996. In addition, the Company provided certain other benefits and services to Mr. Dorn. The present value of the severance package was estimated at $500,000, which amount was recorded as an expense and a liability at December 31, 1993. In March 1994, the Company sold certain non-strategic oil and gas properties to an entity controlled by Mr. Dorn and another former executive officer of the Company for net proceeds, after costs of sale and purchase price adjustments, of $3,661,000. The Company established the sales price based upon an opinion from an independent third party.
(12) COMMITMENTS AND CONTINGENCIES: - --------------------------------------------------------------------------------
Future rental payments for office facilities and equipment under the remaining terms of noncancelable leases are $1,810,000, $1,810,000, $1,773,000, $1,615,000 and $1,090,000 for the years ending December 31, 1997 through 2001, respectively.
Net rental payments applicable to exploration and development activities and capitalized in the oil and gas property accounts aggregated $1,050,000 in 1996, $972,000 in 1995 and $851,000 in 1994. Net rental payments charged to expense amounted to $3,336,000 in 1996, $3,529,000 in 1995 and $3,512,000 in 1994. Rental payments include the short-term lease of vehicles. None of the leases are accounted for as capital leases.
A significant portion of Canadian Forest's natural gas production is sold through the ProMark Netback Pool. At December 31, 1996 the ProMark Netback Pool had entered into fixed price contracts to sell approximately 10.7 BCF of natural gas in 1997 at an average price of $1.66 per MCF and approximately 5.4 BCF of natural gas in 1998 at an average price of approximately $1.88 per MCF. Canadian Forest is obligated to deliver approximately 25% of the volumes of natural gas subject to these contracts.
As part of ProMark's gas marketing activities, ProMark has entered into fixed price contracts to purchase and to resell natural gas through 1998. ProMark has commitments to purchase and commitments to resell approximately 300,000 MCF per day through October 31, 1997 and approximately 35,000 MCF per day thereafter through October 31, 1998. The Company could be exposed to loss in the event that a counterparty to these agreements failed to perform in accordance with the terms of the agreements.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(12) COMMITMENTS AND CONTINGENCIES (CONTINUED):
The Company, in the ordinary course of business, is a party to various legal actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, liquidity or results of operations.
(13) FINANCIAL INSTRUMENTS:
ENERGY SWAPS AND COLLARS: In order to hedge against the effects on the Company's future oil and gas production of declines in oil and natural gas prices, the Company enters into energy swap agreements with third parties and accounts for the agreements as hedges based on analogy to the criteria set forth in Statement of Financial Accounting Standards No. 80, "Accounting for Futures Contracts". In a typical swap agreement, the Company receives the difference between a fixed price per unit of production and a price based on an agreed-upon third party index if the index price is lower. If the index price is higher, the Company pays the difference. The Company's current swaps are settled on a monthly basis. For the years ended December 31, 1996, 1995 and 1994, the Company's gains (losses) under its swap agreements were $(10,422,000), $3,536,000 and $1,810,000, respectively. The Company also enters into collar agreements with third parties that are accounted for as hedges. A collar agreement is similar to a swap agreement, except that the Company receives the difference between the floor price and the index price only if the index price is below the floor price, and the Company pays the difference between the ceiling price and the index price only if the index price is above the ceiling price.
The following table indicates outstanding energy swaps at December 31, 1996:
(1) Energy swaps related to the oil and gas operations of Canadian Forest and Saxon.
(2) Based on Alberta Energy Company "C" (AECO "C", U.S. $) basis. All other swaps are settled on the basis of New York Mercantile Exchange (NYMEX) prices.
Subsequent to December 31, 1996 the Company entered into two additional oil swaps. The first oil swap hedges 200 barrels of oil per day from February 1997 to July 1997 at a fixed price of $23.67 per barrel (NYMEX basis). The second oil swap hedges 247 barrels of oil per day from January 1998 to December 1998 at a fixed price of $20.00 per barrel (NYMEX basis).
The Company also uses basis swaps in connection with energy swaps to fix the differential between the NYMEX price and the index price at which the hedged gas is to be sold. At December 31, 1996 there are six basis swaps in place through April 1998, for a weighted average volume of 22,000 MMBTU/day. Subsequent to December 31, 1996 the Company entered into six additional basis swaps through December 1997, for a weighted average volume of 18,000 MMBTU/day.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(13) FINANCIAL INSTRUMENTS (CONTINUED):
At December 31, 1996 the Company has an outstanding collar to hedge 10,000 MMBTU of natural gas per day from January 1997 through December 1997. The floor and ceiling price of the collar are $2.00 and $2.37 per MMBTU (NYMEX basis), respectively. Subsequent to December 31, 1996 the Company entered into a collar to hedge 7,000 MMBTU of gas per day from April 1997 to September 1997. The floor and ceiling price of the collar are $2.10 and $2.50 per MMBTU (NYMEX basis), respectively.
At December 31, 1996 the Company has an outstanding call which covers 10,000 MMBTU of natural gas per day from Janary 1997 to December 1997. In this arrangement, the Company has effectively set a ceiling price of $2.00 per MMBTU (NYMEX basis) in exchange for a premium of $.086 per MMBTU.
The Company is exposed to off-balance-sheet risks associated with swap or collar 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 or collar agreements.
Set forth below is the estimated fair value of certain on- and off-balance sheet financial instruments, along with the methods and assumptions used to estimate such fair values as of December 31, 1996:
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE: The carrying amount of these instruments approximates fair value due to their short maturity.
PRODUCTION PAYMENT OBLIGATION: The fair value of the Company's production payment obligation has been estimated as approximately $11,188,000 by discounting the projected future cash payments required under the agreement by 9.7%.
SENIOR SUBORDINATED NOTES: The fair value of the Company's 11 1/4% Senior Subordinated Notes was approximately $107,500,000, based upon quoted market prices of the Notes.
INTEREST RATE SWAP AGREEMENTS: The fair value of the Company's interest rate swap agreements was a loss of approximately $1,751,000, of which approximately $1,168,000 has been recorded as a liability at December 31, 1996.
ENERGY SWAP AGREEMENTS: The fair value of the Company's energy swap agreements was a loss of approximately $5,615,000, based upon the estimated net amount the Company would have to pay to terminate the agreements.
BASIS SWAP AGREEMENTS: The fair value of the Company's basis swap agreements was a gain of approximately $173,000, based upon the estimated net amount the Company would receive to terminate the agreements.
ENERGY COLLAR AGREEMENTS: The fair value of the Company's energy collar agreements was a loss of approximately $109,000, based upon the estimated net amount the Company would have to pay to terminate the agreements.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(14) MAJOR CUSTOMERS:
The Company's sales to individual customers which exceeded 10% of the Company's total revenue in 1995 and 1994 (exclusive of the effects of energy swaps and hedges) are shown below. No single customer accounted for more than 10% of total revenue in 1996.
1995 1994 ------- ------ (In Thousands) Enron Affiliates $30,916 58,805 Chevron USA Production Company 11,893 12,829
The amount shown for Enron Affiliates includes oil and natural gas sales to Enron Gas Marketing Inc., Enron Oil & Gas Company, EOTT Energy Corporation, Cactus Funding Corporation, Cactus Hydrocarbon III Limited Partnership, Enron Gas Services Corporation and Enron Reserve Acquisition. Approximately $6,272,000, $17,217,000 and $29,046,000 represent sales recorded for deliveries under volumetric production payments in the years ended December 31, 1996, 1995 and 1994, respectively.
(15) GAS CONTRACT SETTLEMENT:
The Company had gas sales contracts with Columbia Gas Transmission (Columbia) which were rejected by Columbia in 1991 in connection with its bankruptcy proceedings. The Company had a secured claim of approximately $1,600,000 relating to Columbia's failure to pay the contract price for a period of time prior to the rejection of the contracts. This amount was recorded as natural gas sales when the gas was delivered in 1991. The Company also had an unsecured claim relating to the rejection of the gas purchase contracts.
The Company established a reserve of approximately $750,000 against the secured portion of the bankruptcy claim in 1991. This reserve was reversed in 1994 when it became apparent that the amount the Company would receive in the Columbia settlement would exceed the amount of the secured claim. The reversal of the reserve was recorded as miscellaneous revenue in 1994.
In 1995, the creditors reached agreement with Columbia regarding settlement of the various claims. The Company recorded approximately $4,263,000 of revenue as a result of the settlement. This amount represents the Company's portion of the settlement amount related to its unsecured claim, net of a provision for royalties payable.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(16) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED):
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(17) BUSINESS AND GEOGRAPHICAL SEGMENTS: - ------------------------------------------------------------------------------
The Company operates in geographic segments in the United States and Canada, and in two business segments as follows:
UNITED STATES CANADA TOTAL ------ ------ ----- (IN THOUSANDS)
- ---- GAS MARKETING AND PROCESSING: REVENUE $ 927 186,447 187,374 --------- ------- ------- --------- ------- -------
DEPRECIATION AND DEPLETION EXPENSE $ - 2,263 2,263 --------- ------- ------- --------- ------- -------
OPERATING PROFIT $ 927 5,478 6,405 --------- ------- ------- --------- ------- -------
IDENTIFIABLE ASSETS $ - 54,215 54,215 --------- ------- ------- --------- ------- -------
CAPITAL EXPENDITURES $ - 6,183 6,183 --------- ------- ------- --------- ------- -------
OIL AND GAS OPERATIONS: REVENUE $ 80,811 47,902 128,713 --------- ------- ------- --------- ------- -------
DEPRECIATION AND DEPLETION EXPENSE $ 39,880 20,925 60,805 --------- ------- ------- --------- ------- -------
OPERATING PROFIT $ 21,142 14,567 35,709 --------- ------- ------- --------- ------- -------
IDENTIFIABLE ASSETS $ 326,399 182,844 509,243 --------- ------- ------- --------- ------- -------
CAPITAL EXPENDITURES $ 74,734 169,384 244,118 --------- ------- ------- --------- ------- -------
In 1995 and 1994, the Company's only business segment was oil and gas operations, which were conducted entirely in the United States.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) 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), except as noted.
(A) COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES - The following costs were incurred in oil and gas exploration and development activities during the years ended December 31, 1996, 1995 and 1994:
UNITED STATES CANADA TOTAL ------- ------ ----- (In Thousands) - ---- PROPERTY ACQUISITION COSTS (UNDEVELOPED LEASES AND PROVED PROPERTIES) $ 16,122 142,833 (1) 158,955 EXPLORATION COSTS 36,696 6,743 43,439 DEVELOPMENT COSTS 21,916 19,808 41,724 -------- ------- ------- TOTAL $ 74,734 169,384 244,118 -------- ------- ------- -------- ------- -------
- ---- Property acquisition costs (undeveloped leases and proved properties) $ 844 25,963 (2) 26,807 Exploration costs 12,739 - 12,739 Development costs 13,198 - 13,198 -------- ------- ------- Total $ 26,781 25,963 52,744 -------- ------- ------- -------- ------- -------
- ---- Property acquisition costs (undeveloped leases and proved properties) $ 9,762 - 9,762 Exploration costs 15,693 - 15,693 Development costs 17,089 - 17,089 -------- ------- ------- Total $ 42,544 - 42,544 -------- ------- ------- -------- ------- -------
(1) Consists primarily of the oil and gas properties acquired in the purchase of Canadian Forest. (2) Consists of the oil and gas properties acquired in the purchase of Saxon.
(B) AGGREGATE CAPITALIZED COSTS - The aggregate capitalized costs relating to oil and gas activities as of December 31 for the years indicated are as follows:
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - ------------------------------------------------------------------------------
(C) RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES - Results of operations from producing activities for the years ended December 31, 1996, 1995 and 1994 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.
(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 1994, 1995 and 1996 follows. The Canadian reserves at December 31, 1996 and 1995 include 100% of the reserves owned by Saxon, a consolidated subsidiary in which the Company holds a majority interest.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangement, including energy swap agreements (see Note 13), but not on escalations based on future conditions.
FOREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - ------------------------------------------------------------------------------
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.
The Company's presentation of estimated proved oil and gas reserves excludes, for each of the years presented, those quantities attributable to future deliveries required under volumetric production payments (see Note 6). In order to calculate such amounts, the Company has assumed that deliveries under volumetric production payments are made as scheduled at expected BTU factors, and that delivery commitments are satisfied through delivery of actual volumes as opposed to cash settlements.
The Company has also presented, as additional information, proved oil and gas reserves including quantities attributable to future deliveries required under volumetric production payments. The Company believes that this information is informative to readers of its financial statements as the related oil and gas property costs and deferred revenue are included on the Company's balance sheets for each of the years presented. This additional information is not presented in accordance with SFAS No. 69; however, the Company believes this additional information is useful in assessing its reserve acquisitions and financial position on a comprehensive basis.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED):
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED):
Purchases of reserves in place represent volumes recorded on the closing dates of the acquisitions for financial accounting purposes. The revisions of previous estimates for natural gas in 1994 include 5,833 MMCF for an adjustment related to the change in accounting for oil and gas sales from the sales method to the entitlements method.
The Company's proved developed reserves, including amounts attributable to volumetric production payments, are shown below. This disclosure is presented as additional information and is not intended to represent required disclosure pursuant to SFAS No. 69.
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS - 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. At December 31, 1996 and 1995, the Canadian amounts include 100% of amounts attributable to the reserves owned by Saxon, a consolidated subsidiary in which the Company holds a majority interest. 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. Future oil and gas sales also include the estimated effects of existing energy swap agreements as discussed in Note 13.
Future income tax expenses are estimated using the statutory tax rate of 35% in the United States and a combined Federal and Provincial rate of 44.62% in Canada. 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.
The Company's presentation of the standardized measure of discounted future net cash flows and changes therein excludes, for each of the years presented, amounts attributable to future deliveries required under volumetric production payments. In order to calculate such amounts, the Company has assumed that deliveries under
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
volumetric production payments are made as scheduled, that production costs corresponding to the volumes delivered are incurred by the Company at average rates for the properties subject to the production payments, and that delivery commitments are satisfied through delivery of actual volumes as opposed to cash settlements.
The Company has also presented, as additional information, the standardized measure of discounted future net cash flows and changes therein including amounts attributable to future deliveries required under volumetric production payments. The Company believes that this information is informative to readers of its financial statements because the related oil and gas property costs and deferred revenue are shown on the Company's balance sheets for each of the years presented. This additional information is not required to be presented in accordance with SFAS No. 69; however, the Company believes this additional information is useful in assessing its reserve acquisitions and financial position on a comprehensive basis.
Undiscounted future income tax expense was $134,835,000 in the United States and $127,833,000 in Canada at December 31, 1996.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
Undiscounted future income tax expense was $22,316,000 in the United States and $2,924,000 in Canada at December 31, 1995.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - ----------------------------------------------------------------------------- (E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
Undiscounted future income tax expense was $1,348,000 at December 31, 1994.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES - An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows. At December 31, 1996 and 1995, the Canadian amounts include 100% of the reserves owned by Saxon, a consolidated subsidiary in which the Company holds a majority interest.
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1996 was based on average natural gas prices of approximately $3.50 per MCF in the U.S. and approximately $2.10 per MCF in Canada and on average liquids prices of approximately $26.25 per barrel in the U.S. and approximately $19.10 per barrel in Canada. During March 1997, the Company was receiving an average natural gas price of approximately $1.90 per MCF in the U.S. and approximately $1.70 per MCF in Canada and was receiving average liquids prices of approximately $19.20 per barrel in the U.S. and approximately $17.00 per barrel in Canada. Had the lower March 1997 prices been used, the Company's standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1996 would have been significantly reduced.
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - ------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
FORREST OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED): - -----------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
DECEMBER 31, -------------- (In Thousands) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at beginning of year $262,176
Changes resulting from: Sales of oil and gas, net of production costs (69,607) Net changes in prices and future production costs (80,526) Net changes in future development costs 7,432 Extensions, discoveries and improved recovery 10,817 Previously estimated development costs incurred during the period 10,000 Revisions of previous quantity estimates 16,840 Sales of reserves in place (10,630) Purchases of reserves in place 8,467 Accretion of discount on reserves at beginning of year before income taxes 32,334 Net change in income taxes 20,246 --------
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at end of year 207,549
Additional disclosures: Amounts attributable to volumetric production payments 22,600 --------
Total discounted future net cash flows relating to proved oil and gas reserves, including amounts attributable to volumetric production payments, at end of year $230,149 -------- --------
PART III
For information concerning Item 10
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) (1) Financial Statements
1. Independent Auditors' Report
2. Consolidated Balance Sheets - December 31, 1996 and 1995
3. Consolidated Statements of Operations - Years ended December 31, 1996, 1995 and 1994
4. Consolidated Statements of Shareholders' Equity - Years ended December 31, 1996, 1995 and 1994
5. Consolidated Statements of Cash Flows - Years ended December 31, 1996, 1995 and 1994
6. Notes to Consolidated Financial Statements - Years ended December 31, 1996, 1995 and 1994
(2) Financial Statement Schedules All schedules have been omitted because the information is either not required or is set forth in the financial statements or the notes thereto.
(3) Exhibits - Forest shall, upon written request to Daniel L. McNamara, Corporate Secretary of Forest, addressed to Forest Oil Corporation, 1600 Broadway, Suite 2200, Denver, CO 80202, 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(i)(a) Certificate of Amendment of the Restated Certificate of Incorporation dated as of July 20, 1995, incorporated herein by reference to Exhibit 3(i)(a) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
Exhibit 3(i)(b) Certificate of Amendment of Restated Certificate of Incorporation dated as of July 26, 1995, incorporated herein by reference to Exhibit 3(i)(b) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
Exhibit 3(i)(c) Certificate of Amendment of the Restated Certificate of Incorporation dated as of January 5, 1996, incorporated herein by reference to Exhibit 3(i)(c) to Forest Oil Corporation's Registration Statement on Form S-2 (File No. 33-64949).
Exhibit 3(ii) Restated By-Laws of Forest Oil Corporation as of May 9, 1990, Amendment No. 1 to By-Laws dated as of April 2, 1991, Amendment No. 2 to By-Laws dated as of May 8, 1991, Amendment No. 3 to By-Laws dated as of July 30, 1991, Amendment No. 4 to By-Laws dated as of January 17, 1992, Amendment No. 5 to By-Laws dated as of March 18, 1993 and Amendment No. 6 to By-Laws dated as of September 14, 1993, incorporated herein by reference to Exhibit 3(ii) to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
Exhibit 3(ii)(a) Amendment No. 7 to By-Laws dated as of December 3, 1993, incorporated herein by reference to Exhibit 3(ii)(a) to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 3(ii)(b) Amendment No. 8 to By-Laws dated as of February 24, 1994, incorporated herein by reference to Exhibit 3(ii)(b) to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 3(ii)(c) Amendment No. 9 to By-Laws dated as of May 15, 1995, incorporated herein by reference to Exhibit 3(ii)(c) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
Exhibit 3(ii)(d) Amendment No. 10 to By-Laws dated as of July 27, 1995, incorporated herein by reference to Exhibit 3(ii)(d) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
Exhibit 4.1 Indenture dated as of September 8, 1993 between Forest Oil Corporation and Shawmut Bank, Connecticut, (National Association), incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
Exhibit 4.2 First Supplemental Indenture dated as of February 8, 1996 among Forest Oil Corporation, 611852 Saskatchewan Ltd. and Fleet National Bank of Connecticut (formerly known as Shawmut Bank, Connecticut, National Association, which was formerly known as The Connecticut Bank), incorporated herein by reference to Exhibit 4.2 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1995 (File No. 0-4597).
Exhibit 4.3 Amended and Restated Credit Agreement dated as of August 31, 1995 between Forest Oil Corporation and Subsidiaries, Borrower and Subsidiary Guarantors and The Chase Manhattan Bank (National Association), as agent, incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1995 (File No. 0-4597).
*Exhibit 4.4 Second Amended and Restated Credit Agreement dated as of January 31, 1997 between Forest Oil Corporation and Subsidiary Guarantors and The Chase Manhattan Bank, as agent.
Exhibit 4.5 Deed of Trust, Mortgage, Security Agreement, Assignment of Production, Financing Statement (Personal Property Including Hydrocarbons), and Fixture Filing dated as of December 1, 1993, incorporated herein by reference to Exhibit 4.6 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 4.6 Amendment No. 1 dated as of June 3, 1994 to the 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, incorporated herein by reference to Exhibit 4.9 of Form 10-K for Forest Oil Corporation for the year ended December 31, 1994 (File No. 0-4597).
Exhibit 4.7 Amendment No. 2 dated as of August 31, 1995 to the 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, incorporated herein by reference to Exhibit 4.14 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1995 (File No. 0-4597).
*Exhibit 4.8 Amendment No. 2 dated as of January 31, 1997 to the Deed of Trust, Mortgage, Security Agreement, Assignment of Production, Financing Statement (Personal Property including Hydrocarbons) and Fixture Filing dated as of June 3, 1994 between Forest Oil Corporation and The Chase Manhattan Bank, as agent.
*Exhibit 4.9 Amendment No. 3 dated as of January 31, 1997 to the 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, as agent.
Exhibit 4.10 Deed of Trust, Mortgage, Security Agreement, Assignment of Production, Financing Statement (Personal Property including Hydrocarbons) and Fixture Filing dated as of June 3, 1994 between Forest Oil Corporation and The Chase Manhattan Bank (National Association), as agent, incorporated herein by reference to Exhibit 4.9 of Form 10-K for Forest Oil Corporation for the year ended December 31, 1994 (File No. 0-4597).
Exhibit 4.11 Amendment No. 1 dated as of August 31, 1995 to Deed of Trust, Mortgage, Security Agreement, Assignment of Production, Financing Statement (Personal Property Including Hydrocarbons), and Fixture Filing dated June 3, 1994, incorporated herein by reference to Exhibit 4.16 on Form 10-K for Forest Oil Corporation for the year ended December 31, 1995 (File No. 0-4597).
Exhibit 4.12 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).
Exhibit 4.13 Amendment No. 1 dated as of July 27, 1995 to Rights Agreement dated as of October 14, 1993 between Forest Oil Corporation and Mellon Securities Trust Company, incorporated herein by reference to Exhibit 99.5 of Form 8-K for Forest Oil Corporation dated October 11, 1995 (File No. 0-4597).
Exhibit 10.1 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 10.2 Form of non-qualified Executive Deferred Compensation Agreement, incorporated herein by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the years ended December 31, 1990 (File No. 0-4597).
Exhibit 10.3 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 10.4 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 10.5 Forest Oil Corporation Stock Incentive Plan and Option Agreement, incorporated herein by reference to Exhibit 4.1 to Form S-8 for Forest Oil Corporation dated June 7, 1996 (File No. 0-4597).
Exhibit 10.6 Letter Agreement with Richard B. Dorn relating to a revision to Exhibit 10.5, 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 10.7 Form of Executive Severance Agreement, incorporated herein by reference to Exhibit 10.9 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 10.8 Shareholders Agreement dated as of July 27, 1995 between Forest Oil Corporation and The Anschutz Corporation incorporated herein by reference to Exhibit 99.7 to Form 8-K for Forest Oil Corporation dated October 11, 1995 (File No. 0-4597).
Exhibit 10.9 Tranche A Warrant to Purchase 3,888,888 shares of Common Stock issued to The Anschutz Corporation dated July 27, 1995 incorporated herein by reference to Exhibit 99.6 to Form 8-K for Forest Oil Corporation dated October 11, 1995 (File No. 0-4597).
Exhibit 10.10 Shareholders Agreement dated as of January 24, 1996 between Forest Oil Corporation and Joint Energy Development Investments Limited Partnership, incorporated herein by reference to Exhibit 10.12 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1995 (File No. 0-4597).
*Exhibit 11 Computation of Earnings Per Share of Common Stock. Forest Oil Corporation and Subsidiaries.
*Exhibit 21 List of Subsidiaries of the Registrant.
*Exhibit 23 Consent of KPMG Peat Marwick LLP
*Exhibit 24 Powers of Attorney of the following Officers and Directors: Philip F. Anschutz, Robert S. Boswell, William L. Britton, Richard J. Callahan, Cortlandt S. Dietler, William L. Dorn, Jordan L. Haines, David H. Keyte, James H. Lee, Craig D. Slater, Joan C. Sonnen, Drake S. Tempest, Michael B. Yanney.
*Exhibit 27 Financial Data Schedule
- --------------------
* filed herewith.
(b) Reports on Form 8-K The following reports on Form 8-K were filed by Forest during the last quarter of 1996:
Date of Report Item Reported Financial Statements Filed -------------- ------------- -------------------------- October 30, 1996 Item 5 None November 15, 1996 Item 5 None
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 27, 1997 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 ---------- ----- ----
Robert S. Boswell* President and Chief Executive March 27, 1997 (Robert S. Boswell) Officer (Principal Executive Officer)
David H. Keyte* Vice President and Chief March 27, 1997 (David H. Keyte) Financial Officer (Principal Financial Officer)
Joan C. Sonnen* Controller March 27, 1997 (Joan C. Sonnen) (Chief Accounting Officer)
Philip F. Anschutz* Directors of the Registrant March 27, 1997 (Philip F. Anschutz)
Robert S. Boswell* (Robert S. Boswell)
William L. Britton* (William L. Britton)
Richard J. Callahan* (Richard J. Callahan)
Cortland S. Dietler* (Cortland S. Dietler)
William L. Dorn* (William L. Dorn)
Jordan L. Haines* (Jordan L. Haines)
James H. Lee* (James H. Lee)
Craig D. Slater* (Craig D. Slater)
Drake S. Tempest* (Drake S. Tempest)
Michael B. Yanney* (Michael B. Yanney)
*By /s/ Daniel L. McNamara March 27, 1997 -------------------------------- Daniel L. McNamara (as attorney-in-fact for each of the persons indicated)