ITEM 1. BUSINESS
OVERVIEW
Forcenergy Inc, a Delaware corporation (the "Company" or "Forcenergy"), formerly Forcenergy Gas Exploration, Inc., is an independent oil and gas company engaged in the exploration, acquisition, development, exploitation and production of oil and natural gas. Forcenergy and its predecessors have been engaged in the oil and gas exploration and production business since 1982, the year in which it was founded by its current President and Chief Executive Officer, Stig Wennerstrom.
Forcenergy has experienced significant growth in the last eight years, primarily through the exploitation, enhancement and development of acquired producing properties in the Gulf of Mexico and the 1996 acquisition of producing properties in the Cook Inlet, Alaska area. At December 31, 1998, Forcenergy had net proved reserves of approximately 111.0 MMBOE, 64% of which were located in the Gulf of Mexico and 18% of which were located in Alaska. Approximately 44% of the Company's net proved reserves on such date were oil and approximately 73% of proved reserves were classified as proved developed. The Company currently operates approximately 63% of its Gulf of Mexico production. The Company's primary focus is its Gulf of Mexico and Alaska activities. However, the Company has also acquired interests in certain undeveloped international leasehold acreage in Gabon, Africa and Australia.
On March 21, 1999 (the "Petition Date"), the Company and its wholly-owned subsidiary, Forcenergy Resources Inc., filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to facilitate the restructuring of the Company's long-term debt, revolving credit, trade and other obligations. The filing was made in the U.S. District Court for the Eastern District of Louisiana in New Orleans (the "Bankruptcy Court"). The Company continues to operate as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders.
The bankruptcy petitions were filed in order to preserve cash and to give the Company the opportunity to restructure its debt. The consummation of a plan of reorganization is the primary objective of the Company. The plan of reorganization will set forth the means for satisfying claims, including liabilities subject to compromise, and interests in the Company. A plan of reorganization may result in, among other things, material dilution or elimination of existing security holders as a result of the issuance of securities to creditors or new investors. The consummation of a plan of reorganization will require approval of the Bankruptcy Court.
At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect on the business of the Company or on the interests of creditors, royalty owners or stockholders. As a result of the bankruptcy filing, all of the Company's liabilities, including certain secured debt, are subject to compromise.
STRATEGY
The Company's strategy has generally been to increase reserves and cash flows through continuing development of existing properties while selectively acquiring additional properties with upside potential. The Company has historically focused these efforts primarily in the Gulf of Mexico and more recently, the Cook Inlet, Alaska. The Company has also pursued exploratory activities in Gabon, Africa and New South Wales, Australia.
The Company's continued pursuit of its business strategy is subject to Bankruptcy Court supervision. In conjunction with the Chapter 11 filing, the Company's common stock was delisted by the New York Stock Exchange. Shortly after delisting from the New York Stock Exchange, the Company's common stock began trading on the OTC Bulletin Board under the symbol "FENYQ". On May 21, 1999, the symbol was changed to FENYE, the symbol under which the Company's stock currently trades. Although some market for the Company's common stock exists, liquidity and access to debt and equity capital markets has been severely limited. Additionally, the Company is fully drawn under its existing senior credit facility and is currently in violation of various covenants thereunder. The Company is
currently continuing to maintain and maximize the operations of its producing properties by utilizing cash accumulated subsequent to the Chapter 11 filing. The use of that cash is governed by provisions of a court-approved cash collateral order. The Company is also negotiating with potential lenders to provide additional debtor-in-possession financing. The Company is currently preparing a plan of reorganization as yet not submitted to the Bankruptcy Court. Considering the above factors, the Company cannot anticipate or predict the adequacy of working capital or liquidity from which to fund future operations and the continued pursuit of its business strategy.
Gulf of Mexico. The Company's business strategy is to increase reserves and cash flows primarily through the exploration, exploitation and development of its producing properties while also selectively acquiring additional properties with the same type of upside potential. Management believes it has assembled a three to five year inventory of development, exploitation and exploratory drilling opportunities in the Gulf of Mexico predominantly on acreage currently held by production. Most of the prospects comprising this inventory are located in fields which have prolific production histories and which the Company believes, based on the past success of Forcenergy and other industry participants in applying 3-D technology to mature producing properties, will yield additional reserves through the application of modern exploration and development technologies. Forcenergy believes that its high quality asset base positions it for future growth through a continuing program of further development through selective exploitation and exploratory drilling and through the enhancement of production through workovers and recompletions. Forcenergy emphasizes the use of 3-D seismic and computer-aided exploration technology, together with geologic and engineering studies of its properties, to evaluate and prioritize drilling prospects. Focusing drilling activities on producing properties in a relatively concentrated area in the Gulf of Mexico permits Forcenergy to utilize its base of geological, engineering and production experience in the region to maximize its drilling success and to minimize finding and development costs. Furthermore, Forcenergy's concentration of drilling activities on its producing properties allows the utilization of existing infrastructure which greatly reduces incremental lease operating expenses and capital costs associated with new production facilities and minimizes timing delays in commencing production.
Forcenergy prefers to operate its Gulf of Mexico properties because functioning in that capacity positions it to more effectively manage production performance and operating expenses and allows it to control the timing and amount of capital expenditures. As of December 31, 1998, Forcenergy operated 115 structures and 546 wells in the Gulf of Mexico. Forcenergy believes that the operating expertise and experience of its personnel have been instrumental in its ability to enhance and improve production rates and cash flows. Of particular importance, a significant portion of the drilling prospects Forcenergy may pursue during the next three to five years are accessible from existing production facilities operated by the Company.
Cook Inlet, Alaska. Since its discovery, oil and gas activities in the Cook Inlet area have been dominated by major oil companies, which have reduced their activity in the region in recent years as they have refocused their Alaskan efforts mainly to the North Slope (Prudhoe Bay). Forcenergy's business strategy in the Cook Inlet area is to increase production and cash flow through the exploitation of existing producing properties as well as expanding its presence in the Cook Inlet area through selective exploration on undeveloped leases. Forcenergy believes that it has assembled a high quality, producing asset base with exploitation potential as well as the fifth largest exploratory lease position in the State of Alaska, both of which will give Forcenergy an opportunity to add significant new reserves through drilling. Forcenergy recently completed the largest proprietary 3-D seismic survey in Cook Inlet and additional 3-D seismic data is being acquired to identify additional drilling prospects. Forcenergy believes that its strategy, given capital availability, will allow it to economically exploit opportunities previously not pursued by the major oil companies by utilizing proprietary 3-D seismic data, smaller, less capital intensive offshore production facilities and other methods that have proven successful in the Company's operations in the Gulf of Mexico.
International. Forcenergy's international business strategy has historically been aimed at achieving significant reserve growth through participation in selected high risk, high reward exploration projects. The Company also reviews international producing property acquisition opportunities that might provide an operating base from which it could apply its corporate strategy of finding and developing additional reserves on producing properties through the use of advanced technologies. Forcenergy presently holds exploratory acreage offshore Gabon, West Africa and onshore and offshore Australia. The Company is currently in the drilling and testing stage of a pilot project on its coal bed methane gas prospect in New South Wales, Australia. Immediate plans for both areas will be determined, in large part, by the availability of capital during and after the bankruptcy process.
TECHNOLOGY
Forcenergy utilizes advanced technology in its exploration and development activities in order to reduce drilling risks and finding costs and to more effectively prioritize drilling prospects based on return potential. The Company currently has acquired 1,525 square miles of 3-D seismic surveys on 188 of its 217 offshore Gulf of Mexico
lease blocks and 1,700 square miles on other Gulf of Mexico blocks in which it currently does not own an interest. Forcenergy also owns approximately 140,000 linear miles of high quality 2-D seismic data on Gulf of Mexico blocks. Approximately 240 square miles of 3-D seismic data has been recently acquired in the Cook Inlet, Alaska. Additionally, the Company has acquired 973 square miles of 3-D seismic on its exploratory Gryphon Marin concession in Gabon, Africa. The use of the 3-D seismic data has enabled the Company to identify multiple development and exploratory prospects in mature producing fields which were not identified through earlier technologies. Forcenergy's professional staff includes 15 geoscientists experienced in interpreting 3-D data.
1998 DRILLING ACTIVITY
During 1998, Forcenergy continued to focus on increasing reserves and cash flow by targeting development, and exploration prospects on recently acquired properties, with the opportunities developed in most cases through the use of 3-D seismic data. During 1998, Forcenergy spent $271.0 million on capital drilling expenditures, including $14.6 million in capitalized internal costs, $17.6 million in undeveloped leasehold costs and $26.5 million on geological and geophysical costs.
Gulf of Mexico. The Company spent approximately $150.2 million for capital drilling expenditures in the Gulf of Mexico during 1998. Three of four development wells and thirteen of twenty exploratory wells drilled proved successful. The most significant activity centered around the exploitation and development of producing properties. Three successful exploratory wells were drilled at the High Island A-552 field (100% working interest). One development well and three exploratory wells in the Mississippi Canyon 148 field (28.5% working interest) were successfully completed. Additionally, four exploratory wells were completed in the West Cameron 630 field (100% working interest). In the South Timbalier 148 field (15.5% working interest), one development well and one exploratory well were successfully completed. Forcenergy's Gulf of Mexico drilling program added an estimated 8.7 MMBOE to the proved reserve base during 1998.
Cook Inlet, Alaska. Forcenergy completed a successful development well in the 100% owned West McArthur River Field that increased field production by approximately 1,950 BOPD, net to the Company, and added 1,500 MBOE to the proved reserve base by extending the field boundaries. During 1998, the Company spent approximately $10.9 million on 3-D seismic data to better delineate the West McArthur River Field and the Redoubt Shoal prospect, and incurred approximately $15.1 million on the construction of the drilling platform and facilities for the Redoubt Shoal prospect.
Onshore Properties. Approximately $39.4 million in total capital was spent on onshore properties during 1998, $10.7 million of which was primarily incurred on unproved leases primarily in East Texas, and $9.1 million for the acquisition of producing properties in southeastern New Mexico and West Texas.
International. In December 1997 and January 1998, the Company drilled two exploratory dry holes on its Phenix Marin concession located offshore Gabon, West Africa. Additional exploratory opportunities in deeper waters have been identified within the Phenix Marin concession and Forcenergy is currently evaluating future plans for that concession. Forcenergy and its 50% partner on the Gryphon Marin concession acquired during 1998 a large-scale proprietary 3-D seismic survey over the southern portion of the offshore concession that is north of the Phenix Marin concession. Forcenergy believes that numerous drilling opportunities will be generated from the information obtained through this 3-D survey. The Company also believes that there is potential in the northern portion of the Gryphon Marin concession where a recent discovery approximately 5-7 miles from Forcenergy's concession was announced. In May 1999, Forcenergy acquired the remaining 50% of the Gryphon Marin concession it did not already own for $442,000.
In Australia, the Company drilled or reentered 11 wells on its 2.4 million acre PEL 238 concession in New South Wales, a coal bed methane gas prospect. Early indications on this project are that it could develop into a significant find for Forcenergy, however, a more definitive evaluation of the economics of the project will be made after more wells are drilled and the dewatering process is completed.
ADDITIONAL FUTURE PROJECTS
In addition to the activity described above, Forcenergy has identified a substantial inventory of more exploitation, development, exploratory, workover and recompletion projects on its existing Gulf of Mexico and Alaska properties which could be undertaken over the next three to five years after the Company emerges from the Chapter 11 bankruptcy proceedings. Many of these projects are currently being reviewed by Forcenergy's geoscientists utilizing 3-D seismic data acquired in the last three years. The uncertainty of capital availability while the Company operates as a debtor-in-possession subject to Bankruptcy Court supervision and orders, will dictate how many wells the Company will be able to drill in 1999.
GULF OF MEXICO PROPERTIES
Forcenergy currently holds working interests in 217 federal offshore and state lease blocks located in the Gulf of Mexico and Gulf Coast, including a 100% working interest in 51 of these blocks and a 50% or greater working interest in 38 other blocks, and operates 60 of the producing blocks representing 63% of its current Gulf of Mexico/Gulf Coast production. The following table lists the average working interest, net proved reserves and the operator for Forcenergy's nineteen largest offshore Gulf of Mexico properties, comprising approximately 75% of Forcenergy's net proved reserves in the Gulf of Mexico and 48% of Forcenergy's total net proved reserves, as of December 31, 1998:
ALASKA PROPERTIES
Forcenergy currently holds an average 48% working interest in the McArthur River Field (Trading Bay Unit) and a 50% working interest in the Trading Bay Field located in the Cook Inlet area, both non-operated properties purchased from Marathon Oil Company in 1996. Forcenergy also owns a 100% working interest in the operated West McArthur River Field located in the Cook Inlet purchased from Stewart Petroleum Company in June 1997. These fields had estimated net proved reserves of 20.4 million barrels of oil and comprised approximately 18% of
Forcenergy's total estimated net proved reserves at December 31, 1998.
Through leases sales, the Marathon and Stewart acquisitions and several other smaller property acquisitions, Forcenergy has assembled one of the largest exploratory lease acreage positions in the State of Alaska.
ONSHORE PROPERTIES
Forcenergy owns working and royalty interests in approximately 3,000 producing oil and gas wells in 1,064 fields in the Rocky Mountain, Gulf Coast, Permian Basin and Appalachian regions of the United States. Management believes that Forcenergy's stable reserve base of long-lived, primarily non-operated, onshore properties complements the Gulf of Mexico and Alaska operations by providing an additional source of cash flow that requires limited management involvement. Forcenergy's onshore properties accounted for approximately 17% of estimated net proved reserves at December 31, 1998.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, the Company makes only a cursory review of title to farmout acreage and to onshore undeveloped oil and natural gas leases upon execution of the contracts. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. The Company performs complete reviews of title to federal and state offshore lease blocks prior to acquisition. To the extent title opinions or other investigations reflect material title defects, the seller of the property, rather than the Company, is typically responsible for curing any such title defects at its expense. If the Company were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on undeveloped properties, the Company could suffer a loss of its entire investment in the leasehold. The Company has obtained title opinions on substantially all of its producing properties and believes that it has satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Substantially all of the Company's oil and natural gas properties are mortgaged to secure borrowings under the Company's bank loan agreement (the "Senior Credit Facility").
CEILING LIMITATION WRITEDOWNS
The Company reports its operations using the full cost method of accounting for oil and gas properties. Under the full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "ceiling limit", calculated at the end of each quarter, 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, net of related tax effects. 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 flows. However, such writedowns permanently impact the amount of the Company's stockholders' 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. Application of these rules during periods of relatively low oil or gas prices, even if temporary, may result in a ceiling writedown. In addition, writedowns may occur if the Company has substantial downward revisions in its estimated proved reserves or adds significant costs to the full cost pool without adding significant value to its reserve base. Higher operating costs and lower price realizations on production in Alaska make the Company's Alaska reserves more sensitive to price changes and potential writedowns than reserves in the Gulf of Mexico. Based on prices being received as of December 31, 1998 and 1997, the Company recorded in the fourth quarters ended December 31, 1998 and 1997 non-cash impairments of $275 million and $200 million ($162.8 million after tax), respectively pursuant to full cost accounting rules. Though oil and gas prices are currently higher than those at year end, if prices were to decrease again , the Company's capitalized costs could again exceed the present values of estimated future net revenue, which if not offset by other factors, could result in additional writedowns of oil and gas properties. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
ABANDONMENT COSTS
Forcenergy is responsible for the costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on its oil and gas properties, pro rata to its working interest. The Company provides for expected future abandonment liabilities by accruing for such costs as a component of depletion, depreciation and amortization as production occurs. As of December 31, 1998, total undiscounted abandonment costs estimated to be incurred were approximately $118.7 million (undiscounted) for properties in offshore Gulf of Mexico and Alaska waters. For onshore properties, salvage values received for equipment are usually sufficient to offset the abandonment costs. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates, changes in abandonment techniques and technology and changes in environmental laws and regulations. Approximately $2 million in abandonment costs are anticipated to be incurred in 1999.
The Minerals Management Service ("MMS") requires lessees of Outer Continental Shelf ("OCS") properties to post performance bonds in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. Operators in the OCS waters of the Gulf of Mexico are also currently required to post an area wide bond for the lesser of $3 million, or $500,000 per producing lease. The Company currently has additional supplemental bonding on its offshore leases as required by the MMS. Under certain circumstances, the MMS has the authority to suspend or terminate operations on federal leases for failure to comply with applicable bonding requirements or other regulations applicable to plugging and abandonment. Any such suspensions or terminations of the Company's operations could have a material adverse effect on the Company's financial condition and results of operations. To the best of its knowledge, the Company is currently in compliance with all MMS requirements.
COMPETITION
Forcenergy encounters competition from other oil and gas companies in all phases of its operations, including the acquisition of producing properties. Competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling and income programs. Many competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than the Company's and which, in many instances, have been engaged in the energy business for a much longer time. Such companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. Forcenergy's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
MARKETING AND CUSTOMERS
Forcenergy sells substantially all of its natural gas under short-term contracts (maximum of one year in duration) at pricing based on current spot market indexes. A minor portion of the Company's gas production is committed to be processed through gas plants. Crude oil and condensate from Gulf of Mexico and onshore properties is typically sold at the wellhead under short-term contracts at posted market-based field prices.
Most of the Company's production is transported through gas gathering systems and oil and gas pipelines that are not owned by the Company. Transportation space on such gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other companies with priority transportation agreements. Forcenergy's access to transportation options can also be affected by regulation of intrastate and interstate gas transportation. In an attempt to promote competition, the Federal Energy Regulatory Commission ("FERC") has issued a series of orders which have altered significantly the marketing and transportation of natural gas, see "Government Regulation". The effect of these orders to date has been to enable producers such as the Company to market their natural gas production to purchasers other than the interstate pipelines located in the vicinity of their producing properties. While the Company has not experienced any inability to market its production, if transportation space is restricted or is unavailable, the Company's cash flow could be adversely affected.
During 1999, two purchasers of the Company's production individually accounted for more than 10% of the value of oil and gas sold by the Company. Based on current demand for oil and natural gas sold, the Company does not believe the loss of these purchasers would have a material adverse effect on the Company's results of operations or cash flow. The Company currently relies on one purchaser for its Alaska production. The contract with this purchaser runs through December 1999 at which time a new contract must be negotiated or another purchaser found. The net price provided for under this contract is at a slight discount to the posted price for Alaskan North Slope (ANS)-Valdez delivery, after allowance for transportation costs. The inability to negotiate a new contract or to find a new purchaser could materially impact the Company's results of operations and cash flows. (See Note 11 to the Company's Financial Statements).
The Company historically has utilized various financial instruments to hedge portions of its current oil and gas production to achieve more predictable cash flows and to reduce its exposure to fluctuations in oil and gas prices. The remaining portion of current production was not hedged so as to provide the Company the opportunity to benefit from increases in prices on that portion of the production, should price increases materialize. All commodity price hedging contracts in place were cancelled at the option of the counterparty subsequent to the Company's filing under Chapter 11 of the Bankruptcy Code on March 21, 1999. The aggregate fair market value of the cancelled contracts, approximately $5.5 million, was remitted to the Company in April 1999. See Note 8 to the Company's Financial Statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations".
OPERATING RISKS OF OIL AND GAS OPERATIONS
The oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks, any of which could result in substantial losses to the Company through the loss of hydrocarbons, pollution claims, personal injury suits and damage to properties of the Company and others. The Company's offshore operations also are subject to the additional hazards of marine operations, such as severe weather, capsizing and collision that can cause substantial damage to facilities, and possible business interruption. The availability of a ready market for the Company's oil and natural gas production also depends on the proximity of reserves to, and the capacity of, oil and gas gathering systems, pipelines and trucking or terminal facilities. Additionally, the Company may be liable for environmental damages caused by previous owners of property purchased or leased by the Company. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for drilling or acquisitions, or result in the loss of the Company's properties. In accordance with customary industry practices, Forcenergy maintains insurance against some, but not all, of such risks and losses. The Company does not carry business interruption insurance. The occurrence of an event not fully covered by insurance could have a material adverse effect on the financial condition, results of operations and cash flow of the Company.
ENVIRONMENTAL MATTERS
The Company, as an owner or lessee and operator of oil and gas properties, is subject to federal, state and local laws and regulations governing the discharge of materials into, and the protection of, the environment. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from the Company's operations. Stricter standards in environmental legislation may be imposed in the oil and gas industry in the future, such as proposals made in Congress and at the state level from time to time that would reclassify certain oil and natural gas exploration and production wastes as "hazardous wastes" and make the reclassified wastes subject to more stringent and costly handling, disposal and clean-up requirements. The impact of any such changes, however, would not likely be any more burdensome to the Company than to any other similarly situated company involved in oil and gas exploration and production.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes
of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances, for damages to natural resources, and for the costs of certain health studies. Furthermore, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
The Oil Pollution Act of 1990 and regulations promulgated pursuant thereto ("OPA") impose a variety of obligations on "responsible parties" with respect to the prevention of oil spills and liability for damages resulting from such spills. A "responsible party" includes the owner or operator of a facility or vessel that could be the source of an oil spill. For offshore facilities, the responsible party is the lessee or permittee or holder of a right of use and easement (granted under applicable state law or the Outer Continental Shelf Lands Act "OCSLA") of the area in which the offshore facility is located. OPA assigns liability to each responsible part for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a responsible party for an OCS facility must pay all spill removal costs incurred by a federal, state or local government. OPA establishes a liability limit (subject to indexing) for offshore facilities of all removal costs plus $75,000,000. A party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction, or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA.
The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover a substantial portion of environmental clean-up and restoration costs that could be incurred by governmental entities in connection with an oil spill. Other requirements imposed by the OPA include the preparation of an oil spill contingency plan. A failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement action. In short, the OPA places a burden on offshore lease holders to conduct safe operations and take other measures to prevent oil spills; if one occurs, the OPA then imposes liability for resulting damages.
In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of environmental related lease condition or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental prosecution or citizen initiated legal actions.
The Company maintains insurance coverages which it believes are customary in the industry, although it is not fully insured against many environmental risks. Although the Company has not experienced any material adverse effect from compliance with environmental requirements, nor is it aware of any material environmental claims existing at December 31, 1998, there is no assurance that material costs relating to environmental matters will not be incurred in the future.
GOVERNMENT REGULATION
Forcenergy's drilling, production and transportation and marketing operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the surface use and restoration of properties upon which wells are drilling and the plugging and abandonment of wells. Regulations also can limit production rates, require capital for environmental compliance and affect the transportation and marketing of hydrocarbons.
Certain operations the Company conducts are on federal oil and gas leases, which the 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, Army Corps of Engineers and 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 also has issued regulations restricting the flaring or venting of natural gas, and proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization.
In December 1995, the MMS issued an advance notice of proposed rulemaking in which it proposed to amend its regulations governing the calculation of royalties and the valuation of natural gas produced from federal leases. The principle 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 proposed this rulemaking to facilitate royalty valuation in light of changes in the gas marketing environment. The MMS also proposed a rule describing the types of transportation components that are deductible for calculating and reporting royalties, as well as various cost components associated with marketing functions that are not deductible. In addition, the MMS has recently 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 crude 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. These new regulations, as proposed, would have a minimal effect on the Company's past royalty payment practices as the Company's production has been sold solely to non-affiliates. The Company cannot predict what additional 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 if amendments to the regulations are adopted.
In addition, the MMS is conducting an inquiry (not specifically directed at the Company) into certain contractual 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 FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such production. Since the mid-1980s, the FERC has issued a series of orders, culminating in Order Nos. 636, 636-A, 636-B, and 636-C ("Order 636"), that have significantly altered the marketing and transportation of natural gas. Order 636 mandates a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC's purposes in issuing the orders is to increase competition within all phases of the natural gas industry. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately enhance the Company's ability to market and transport its natural gas, although it may also subject the Company to greater competition and more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances. The FERC has issued final orders in all Order No. 636 individual pipeline restructuring proceedings. The United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") has generally affirmed Order No. 636 and remanded certain issues for further explanation or clarification. The issues remanded for further action do not appear to materially affect the Company. A number of parties have appealed the D.C. Circuit's ruling to the United States Supreme Court and proceedings on the remanded issues are currently ongoing before FERC following its issuance of Order No. 636-C in February 1997. Numerous petitions for review of the individual pipeline restructuring orders are currently pending in that court. Although it is difficult to predict when all appeals of pipeline restructuring order will be completed or their impact on the Company, the Company does not believe that it will be affected by the restructuring rule and orders any differently than other natural gas producers and markets with which it competes.
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 that shippers can charge for their released capacity. In addition, in 1995, the 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, any new rules and policy statements may have the effect of enhancing competition in natural gas markets, by among other things, encouraging non-producer natural gas marketers to engage in certain purchase and sale transactions.
The FERC also regulates rates and service conditions for interstate transportation of crude oil, liquids and condensate, which can affect the amount the Company receives from the sale of these products. Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at negotiated prices. Effective January 1, 1995, the FERC adopted regulations establishing an indexing system for transportation rates for oil pipelines, which generally indexes such rates to inflation. The Company is not able to predict what effect, if any, these regulations will have on it however, these regulations, or any amendments to these regulations, could increase the cost of transporting crude oil, liquids and condensate by pipeline.
Cook Inlet Pipeline Company is an interstate common carrier and as such is subject to rate regulation by the FERC under the Interstate Commerce Act ("ICA"). The ICA requires that petroleum pipeline rates be just and reasonable and non-discriminatory. The ICA permits interest parties to challenge proposed new or changes rates and authorizes the FERC to suspend ad to investigate such rates. If upon completion of an investigation, the FERC finds that a proposed new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues collected during the pendency of the investigation in excess of those that would have been collected under the prior rate. In addition, the FERC, upon complaint or on its own motion and after investigation, may order a carrier to change its rate prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint. Cook Inlet Pipeline Company is also subject to regulation by the Alaska Public Utilities Commission with respect to any intrastate transportation Cook Inlet Pipeline Company provides.
Legislation affecting the oil and gas industry is under constant review for amendment or expansion by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective, or their effect, if any, on the Company's operations. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. The regulatory burden on the oil and natural gas industry increases the Company's cost of doing business and, consequently, affects its profitability and cash flow. In as much as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.
ASSUMPTION OR REJECTION OF CONTRACTS
Pursuant to Section 365 of Chapter 11 of the U.S. Bankruptcy Code, the Company has the right to assume or reject executory contracts. The Company is currently reviewing all such contracts.
OFFICES
Forcenergy currently leases approximately 12,600 square feet of office space in Miami, Florida, where its principal offices are located, approximately 44,000 square feet in Metairie, Louisiana, approximately 8,500 square feet in Anchorage, Alaska, and approximately 851 square feet in Lafayette, Louisiana.
EMPLOYEES
As of April 30, 1999, Forcenergy had 250 full time employees, 21 of whom are located at the Company's headquarters in Miami, Florida and 94 of whom are located at the Company's regional offices in Metairie, Lafayette and Intracoastal City, Louisiana, and Anchorage, Alaska. One hundred and twenty-one employees work offshore in the
Gulf of Mexico and fourteen work in other field locations. None of Forcenergy's employees are represented by a labor union.
ITEM 2.
ITEM 2. PROPERTIES
ACREAGE DATA
The following table sets forth the approximate developed and undeveloped acreage in which the Company held a leasehold, mineral or other interest at December 31, 1998. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
(1) The Company has various work/financial commitments that must be met on these concessions over the next two to three years in order to extend the life of each concession. These commitments vary by concession and could include either, or both, of geological studies or seismic operations or the drilling of a well. Should the Company fail to timely meet these commitments, or be granted an extension of time, it could be forced to relinquish its rights to that particular concession.
OIL AND GAS RESERVES
The following table summarizes the estimates of the Company's historical net proved reserves as of January 1, 1999 and the present values attributable to those reserves on such date using constant prices and operating costs as of the valuation date, discounted at a rate of 10% per annum, in accordance with Securities and Exchange Commission ("Commission") guidelines. The reserve data and present values as of January 1, 1999 for the onshore properties have been estimated by Netherland, Sewell & Associates, Inc., independent petroleum engineering consultants. The reserve data and present values as of January 1, 1999 for the offshore and Alaska properties have been estimated by the Company and the reserve data has been audited by Collarini Engineering Inc., independent petroleum engineering consultants.
- ------------ (1) Includes crude oil, condensate and natural gas liquids. (2) The standardized measure of discounted future net cash flows represents the present value of future net revenues after income taxes discounted at 10% in accordance with Statement of Financial Accounting Standards No. 69.
Since January 1, 1998, the Company has not filed any estimates of proved oil and gas reserves with any federal authority or agency other than with the Commission.
DRILLING ACTIVITY
The following table sets forth the completed drilling activity of the Company on its properties for the twelve month periods ended December 31, 1998, 1997 and 1996.
PRODUCTIVE WELLS
The following table sets forth the number of productive oil and gas wells in which the Company owned a working interest at December 31, 1998:
Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. The Company has only 21 wells that are completed in more than one producing horizon; those wells have been counted as single wells.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On March 21, 1999, the Company and its wholly owned subsidiary, Forcenergy Resources Inc., filed voluntarily under Chapter 11 of the U.S. Bankruptcy Code in order to facilitate the restructuring of the Company's long-term debt, revolving credit, trade and other obligations. The Company continues to operate as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders. The filing was made in the U.S. District Court for the Eastern District of Louisiana in New Orleans.
Forcenergy is not a party to, nor are any of its properties subject to, any other pending legal proceedings that in the opinion of management, are likely to have a material adverse effect on its financial condition or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of the Company's fiscal year ended December 31, 1998.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Prior to the Petition Date, the Company's common stock was listed on the New York Stock Exchange (the "NYSE") under the symbol "FEN". Prior to June 18, 1997, the Company's stock was quoted on the NASDAQ National Market (the "NASDAQ") under the symbol "FGAS". The following table sets forth, for the periods indicated, the range of closing high and low prices of the common stock as reported by the NYSE and the NASDAQ.
At May 31, 1999, the Company had approximately 4,300 shareholders of record of its common stock. The Company estimates that an additional 10,000 shareholders hold Forcenergy's common stock in street name. On March 22, 1999, the New York Stock Exchange suspended trading in the Company's common stock because of the Chapter 11 bankruptcy filing. The Company was then delisted. Forcenergy's common stock was then quoted on the NASD OTC Bulletin Board under the trading symbol "FENYQ", until May 21, 1999 when the symbol was changed to "FENYE."
FORCENERGY AB ACQUISITION
On December 19, 1997 Forcenergy made a public tender offer for all of the outstanding shares of Forcenergy AB ("FAB"), a Swedish public company that owned approximately 34% of Forcenergy's common stock. FAB was formed in 1990 to provide capital for Forcenergy's oil and gas operations in the United States and currently owns 8,740,486 shares of Forcenergy common stock, its only significant asset. The issuance of the Forcenergy shares pursuant to the terms of the tender offer was approved by Forcenergy Inc shareholder vote on March 17, 1998. On March 31, 1998, 97% of the outstanding common shares of FAB had been tendered in connection with the offer and all conditions of the offer were met. As of December 1998, 99.3% of the outstanding FAB shares had been tendered and Forcenergy had issued approximately 7.9 million new shares valued at $27 per share (the price of the Company's common stock on the date the tender offer was initiated) in exchange for the tendered shares. The 8,740,486 Forcenergy shares owned by FAB are now controlled by Forcenergy, therefore for accounting and voting purposes are no longer considered outstanding. The acquisition was accounted for as a purchase.
DIVIDEND POLICY
Certain covenants set forth in the Company's Senior Credit Facility and the 9 1/2% and 8 1/2% Senior Subordinated Notes restrict and/or limit the ability of the Company to pay cash dividends. The Company is also prohibited from paying cash dividends without approval of the Bankruptcy Court. Forcenergy does not contemplate the payment of any cash dividends in the near future.
ITEM 6.
ITEM 6. SELECTED FINANCIAL INFORMATION
The following table sets forth selected historical financial data for the Company as of and for each of the periods indicated. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's financial statements included elsewhere in this report.
- ----------------- (1) Natural gas liquid revenues for 1994 have been reclassified from other revenues to oil and gas sales for consistent presentation with 1998, 1997, 1996 and 1995 revenues.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the Company's historical financial position and results of operations for each of the three years ended December 31, 1998 and should be read in conjunction with the financial statements of the Company appearing elsewhere in this report.
RESULTS OF OPERATIONS
OPERATIONS
The following table sets forth the Company's historical operations data during the periods indicated:
- ------------- (1) Includes crude oil, condensate and natural gas liquids. (2) Net of effects of hedging. (3) Excludes $275 million and $200 million impairment provisions recorded in the fourth quarters of 1998 and 1997, respectively.
COMPARISON OF THE YEARS ENDED DECEMBER 31, 1998 AND DECEMBER 31, 1997
Operating and Net Income/Loss. The Company reported an operating loss of $268.0 million for the year ended December 31, 1998, compared to the $126.4 million operating loss recorded for the prior year. Net loss for 1998 was $314.5 million compared to a net loss of $134.8 million in 1997. The decrease in operating income and net income is mainly attributable to lower oil and gas prices, incremental lease operating expenses from new properties acquired, higher depletion, depreciation and amortization associated with higher production volumes, a larger non-cash impairment of oil and gas assets recorded in 1998 pursuant to full cost accounting rules mandated by the Commission and higher interest expense, all of which are discussed below. Excluding the impairment provisions, operating income for 1998 and 1997 would have been $7.0 million and $73.6 million, respectively.
Production. The Company's net liquids production rose to 8,513 MBbls in 1998 from 8,210 MBbls in 1997, a 4% improvement. Net gas production increased to 76,799 MMcf for the year ended December 31, 1998, a 33% increase over the 57,737 MMcf produced in 1997. On an equivalent unit basis, 1998 production increased to 21,313 MBOE, 20% more than the 17,833 MBOE produced during 1997. The increase in equivalent production resulted from producing properties in the Gulf of Mexico acquired late 1997 and early 1998 and from the success of the Company's late 1997 and 1998 drilling and workover programs.
Revenues. Revenues were $273.5 million for the year ended December 31, 1998, compared to $284.2 million reported last year, as lower net realized prices only partially offset by higher production volumes. Average net realized liquid prices declined to $12.54 per Bbl in 1998, a 28% decrease compared with $17.34 per Bbl received in 1997. Average net realized gas prices declined to $2.16 per Mcf in 1998, a 10% decrease compared with $2.41 per Mcf reported in 1997.
Average prices received for field production for 1998 were $11.59 per Bbl and $2.06 per Mcf for liquids and natural gas, respectively. After taking into account the effects of 1998 hedging activities entered into in order to guarantee a certain level of cash flow from production, specifically an $8.0 million increase in liquids revenue and a $7.7 million increase in gas revenue, net realized prices were $12.54 per Bbl and $2.16 per Mcf for liquids and natural gas, respectively. All commodity price hedging contracts in place were cancelled at the option of the counterparty pursuant to the filing under Chapter 11 of the U.S. Bankruptcy Code on March 21, 1999. The aggregate fair market value of the cancelled contracts, approximately $5.5 million, was remitted to the Company in April 1999. Average field prices for 1997 were $17.70 per Bbl and $2.55 per Mcf for liquids and natural gas, respectively. After taking into account the effects of 1997 hedging activities, specifically a $2.9 million reduction in liquids revenue and a $7.9 million reduction in gas revenue, net realized prices were reduced to $17.34 per Bbl and $2.41 per Mcf for liquids and natural gas, respectively.
Lease Operating Expenses. Lease operating expenses were $99.2 million in 1998 compared to $77.2 million in 1997. The increase related primarily to new oil and gas properties acquired in late 1997 and early 1998. On an equivalent unit of production basis, lease operating expenses increased to $4.66 per BOE in 1998 from $4.33 per BOE in 1997, an increase attributable to slightly higher lease operating expenses associated with new properties acquired and higher 1998 workover costs.
Depletion, Depreciation and Amortization ("DD&A"). DD&A expense increased to $420.9 million in 1998 from $313.3 million for 1997. DD&A expense, not including impairment provisions, was $145.9 million in 1998 compared to $113.3 million in 1997. The increase was principally attributable to higher production volumes and an increase in the rate from $6.36 per BOE in 1997 to $6.84 per BOE in 1998. In addition, the Company recorded non-cash impairments of oil and gas assets in the fourth quarter of 1998 for $275 million and $200 million in the fourth quarter of 1997.
General and Administrative Expense. General and administrative expense, net of overhead reimbursements and capitalized internal costs, was $17.2 million in 1998 compared with $15.2 million in 1997. This increase was attributable to the overall growth of the Company. On a barrel equivalent basis, general and administrative expenses decreased by 5% to $.81 per BOE in 1998 from $.85 per BOE in 1997.
Interest and Other Income. Interest and other income decreased to $1.6 million in 1998 from $3.4 million in 1997. The decrease was primarily attributable to a decline in the Company's equity in the earnings of Cook Inlet Pipeline Company, a 30% owned affiliate acquired in early 1997.
Interest Expense. Interest expense, net of amounts capitalized, increased to $48.1 million in 1998, compared to the $32.4 million recorded in 1997. The increase in interest expense was due primarily to increased long-term debt levels.
Income Tax Provision/Benefit. Due to net losses incurred during 1998, an income tax provision was not recorded during 1998. The $20.6 million income tax benefit reported in 1997 resulted from the $200 million non-cash impairment of oil and gas properties recorded in the fourth quarter of 1997.
COMPARISON OF THE YEARS ENDED DECEMBER 31, 1997 AND DECEMBER 31, 1996
Operating and Net Income/Loss. The Company recorded an operating loss of $126.4 million for the year ended December 31, 1997, compared to the $30.7 million operating income reported for the prior year. Net loss for 1997 was $134.8 million compared to net income of $11.3 million in 1996. The decline in operating income and net income is attributable to a $162.8 million ($200 million pre-tax) non-cash impairment of oil and gas assets recorded pursuant to full cost accounting rules mandated by the Commission. Excluding the impairment provision, operating income would have been $73.6 million, a 140% increase over 1996, that was attributable to higher production volumes and higher commodity prices received during 1997.
Production. The Company's net liquids production rose to 8,210 MBbls for the year ended December 31, 1997 from 4,006 MBbls in 1996, a 105% improvement. Net gas production increased to 57,737 MMcf in 1997, a 76% increase over the 32,738 MMcf produced last year. On an equivalent unit basis, 1997 liquids and gas production increased to 17,833 MBOE, 88% more than the 9,462 MBOE produced during 1996. The increase in equivalent production resulted from new oil production in the Cook Inlet, Alaska area acquired in December 1996, from producing properties in the Gulf of Mexico acquired late 1996 and 1997, and from the success of the Company's late 1996 and 1997 drilling and workover programs.
Revenues. Revenues for 1997 increased to $284.2 million, a 104% improvement over $139.4 million in 1996, primarily because of higher production volumes and higher net realized prices. Average net realized liquid prices rose to $17.34 per Bbl in 1997, a 1% increase over the $16.93 per Bbl received in 1996. Average net realized gas prices rose to $2.41 per Mcf in 1997, a 12% increase over the $2.16 per Mcf reported in 1996.
Average prices received for field production for the 1997 year were $17.70 per Bbl and $2.55 per Mcf for liquids and natural gas, respectively. After taking into account the effects of 1997 hedging activities entered into to guarantee a certain level of cash flow from production, specifically a $4.9 million reduction in liquids revenue and a $5.8 million reduction in gas revenue, net realized prices were reduced to $17.34 per Bbl and $2.41 per Mcf for liquids and natural gas, respectively. Average field prices for 1996 were $20.13 per Bbl of liquids and $2.40 per Mcf of gas. After taking into account the effects of 1996 hedging activities entered into to guarantee a certain level of cash flow from production, specifically a $12.8 million reduction in liquids revenue and a $7.7 million reduction in gas revenue, net realized prices were reduced to $16.93 per Bbl and $2.16 per Mcf for liquids and natural gas, respectively.
Lease Operating Expenses. Lease operating expenses were $77.2 million in 1997 compared to $38.8 million in 1996. On an equivalent unit of production basis, lease operating expenses increased to $4.33 per BOE in 1997 from $4.08 per BOE in 1996 an increase attributable t the higher costs in the non-operated Cook Inlet, Alaska fields. For the Gulf of Mexico properties, which are primarily operated fields, lease operating expenses per BOE were reduced by 16% to $3.22 in 1997 compared with $3.84 in 1996, due to increased production and to operating improvements.
Depletion, Depreciation and Amortization. DD&A expense increased to $313.3 million in 1997 from $58.5 million reported for 1996, an increase primarily attributable to a $200 million non-cash impairment of oil and gas
assets in the fourth quarter of 1997. Excluding the impairment provision, DD&A would have been $113.3 million compared to the $58.5 million in 1996, or $6.36 and $6.18 per BOE, respectively.
General and Administrative Costs. General and administrative expense, net of overhead reimbursements and capitalized internal costs, was $15.2 million in 1997 compared with $8.0 million reported in 1996. This increase was attributable to the overall growth of the Company, including the opening of an Anchorage, Alaska office. On a barrel equivalent basis, general and administrative expenses remained flat at $.85 per BOE and $.84 per BOE for 1997 and 1996, respectively.
Interest and Other Income. Interest and other income increased to $3.4 million in 1997 from $650,000 in 1996. The increase resulted primarily from $1.5 million attributable to the Company's equity in the earnings of Cook Inlet Pipeline Company, a 30% owned affiliate acquired in January 1997 as part of the acquisition of producing oil properties in the Cook Inlet area of Alaska.
Interest Expense. Interest expense, net of amounts capitalized, increased to $32.4 million in 1997, compared to $13.4 million in 1996. The increase in interest expense was due primarily to increased debt levels. Interest rates were slightly higher in 1997 as borrowings under the Senior Credit Facility were repaid through issuance of fixed rate, long-term subordinated debt issued in late 1996 and early 1997.
Income Tax Provision/Benefit. The Company recorded an income tax benefit in 1997 of $20.6 million compared to an income tax expense of $6.7 million in 1996. The benefit resulted from the $200 million non-cash impairment of oil and gas assets recorded in 1997. The recording of a valuation allowance for a portion of the deferred tax asset created by the year end impairment provision resulted in a reduction in the effective tax rate to 13.3% in 1997, from 37.3% in 1996.
LIQUIDITY AND CAPITAL RESOURCES
On March 21, 1999, the Company and its wholly-owned subsidiary, Forcenergy Resources Inc., filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to facilitate the restructuring of the Company's long-term debt, revolving credit, trade and other obligations. The filing was made in the U.S. District Court for the Eastern District of Louisiana in New Orleans. The Company continues to operate as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders.
The bankruptcy petitions were filed in order to preserve cash and to give the Company the opportunity to restructure its debt. The consummation of a plan of reorganization is the primary objective of the Company. The plan of reorganization will set forth the means for satisfying claims, including liabilities subject to compromise, and interests in the Company. A plan of reorganization may result in, among other things, material dilution or elimination of existing security holders as a result of the issuance of securities to creditors or new investors. The consummation of a plan of reorganization will require approval of the Bankruptcy Court.
At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect on the business of the Company or on the interests of creditors, royalty owners or stockholders. There can be no assurance that the plan of reorganization to be submitted by the Company will be approved or that the Bankruptcy Court will permit the Company to continue to operate as a debtor-in-possession. As a result, there is substantial doubt about the Company's ability to continue as a going concern. See the Consolidated Financial Statements of the Company included under Item 8 of this report.
In the ordinary course of business, the Company makes substantial capital expenditures for the exploration and development of oil and natural gas reserves. Historically, the Company has financed its capital expenditures, debt service and working capital requirements with cash flow from operations, public offerings of equity, private offerings of debt, asset sales, a senior credit facility and other financings. Cash flow from operations is sensitive to the prices the Company receives for its oil and natural gas. A reduction in planned capital spending or an extended decline in oil and gas prices could result in less than anticipated cash flow from operations in the current fiscal year
and in later years which could have a material adverse effect on the Company. Proceeds from oil and natural gas sales are received at approximately the same time that production-related burdens, such as royalties, production taxes and drilling program obligations, are payable.
After the bankruptcy Petition Date, Forcenergy and Resources filed an Emergency Motion for Interim Order Authorizing Use of Cash Collateral (the "Cash Collateral Motion"), pursuant to which Forcenergy and Resources sought the use of various purported secured parties' cash collateral in on-going operations. On March 22, 1999, the Bankruptcy Court signed a Preliminary Order Authorizing Use of Cash Collateral, thereby authorizing Forcenergy's and Resource's use of cash collateral in accordance with a budget attached thereto. Since the Preliminary Order, the Bankruptcy Court has conducted several hearings on Forcenergy's and Resource's continued use of cash collateral and on May 14, 1999, the final order (the Order Authorizing the Use of Cash Collateral) was signed.
Forcenergy is presently in negotiations for debtor-in-possession financing.
Presently, Forcenergy and Resources are operating pursuant to the Order Authorizing the Use of Cash Collateral and the budget attached thereto. To the extent that on-going expenses are for post petition goods and services (after March 21, 1999), are within the ordinary course of business and are reflected on the court-approved budget, Forcenergy and Resources are permitted to make such expenditures without further Bankruptcy Court order. Any expenditure, however, that is outside the ordinary course of business or that is not reflected on the budget, must be specifically authorized by the Bankruptcy Court. The procedures for payment of such expenses may be further specified in a debtor-in-possession financing facility. The Company had approximately $42 million in cash on hand on May 31, 1999 that can be used for such operations pursuant to the terms of the Cash Collateral Order.
The Company has historically funded its operations, acquisitions, capital expenditures and working capital requirements from cash flow from operations, bank borrowings and private and public placements of debt and equity securities. The Company's primary sources of funds for each of the past three years were as follows:
Cash flow from operations, before changes in operating assets and liabilities, was $107.4 million for the year ended December 31, 1998, compared with $157.7 million in 1997. The decrease in cash flow resulted primarily from the lower oil and gas prices and higher interest expense.
Capital expenditures were $337.4 million, including $54.0 million for acquisitions, for the year ended December 31, 1998, compared with $406.7 million in 1997. Capital expenditures were funded by the Company's existing Senior Credit Facility and cash generated from operations. As a result, the Company's long-term debt increased from $506.6 million at the end of 1997 to $671.7 million (all reclassified as liabilities subject to compromise) at December 31, 1998. The Company was fully drawn under the Senior Credit Facility at March 21, 1999.
The Company's capital expenditures for 1999 will remain subject to the approval and supervision of the Bankruptcy Court and may vary significantly due to a variety of factors, including drilling results, oil and gas prices, industry conditions and outlook, future acquisitions of properties and the availability of capital.
YEAR 2000 COMPLIANCE
Forcenergy has established a "Year 2000" project (the "Project") to assess, to the extent possible, its Year 2000 risk exposure, to take remedial actions necessary to minimize the Year 2000 risk exposure to Forcenergy and to test its systems and processes once remedial actions have been taken. Because of the importance of occurrence dates in the oil and gas industry, the consequences of not pursuing Year 2000 modifications could be critical to Forcenergy's ability to manage and report operating activities. The costs to the Company associated with the Project are not expected to have a material financial impact on the Company.
The assessment phase of the Project is 90% complete as of December 31, 1998, with the remainder being the assessment of risk related to year 2000 failure on the part of the Company's customers and vendors. This phase included, among other procedures, the assessment of information technology applications and systems; the assessment of non-information technology exposures; the initiation of inquiry and dialogue with significant third party business partners, customers and suppliers in an effort to understand their Year 2000 readiness and its potential impact on Forcenergy; and, the formulation of contingency plans for mission-critical information technology systems. Forcenergy expects to complete the assessment phase of its Year 2000 project by the end of the second quarter of 1999 but is being delayed by limited responses to inquiries made to third party businesses. The Company does believe, however, that any equipment failure at the customer/vendor level could be overcome by a change in provider or by the implementation of manual procedures. The remedial phase of the Project was approximately 80% complete as of December 31, 1998, subject to the results of third party inquiry assessments. The remediation of non-information technology is expected to be completed by mid-1999. The testing phase of the Project is expected to by completed by mid-1999, subject to the Company's assessment of customer and vendor inquiries.
Although Forcenergy is making every effort to mitigate the risks associated with the Year 2000 problem, and currently believes that no material risk exists that has not been mitigated, there can be no assurance that the Project or resulting contingency plans will have anticipated all Year 2000 scenarios. A failure to remedy a critical Year 2000 problem could result in information and non-information technology failures, the receipt or transmission of erroneous data, lost data or a combination of similar problems of a magnitude that cannot be accurately assessed at this time.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"). The statement requires companies to report the fair market value of derivatives on the balance sheet and record in income or other comprehensive income, as appropriate, any changes in the fair value of the derivative. Statement No. 133 will become effective with respect to the Company on January 1, 2000. The Company is currently evaluating the impact, if any, of SFAS No. 133.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Revenues generated from operations are highly dependent upon the price of, and demand for, oil and natural gas. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future as prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These uncontrollable factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels and political and economic conditions in the Middle East, Russia, Mexico and Canada that can affect the supply and price of foreign oil and natural gas. It is impossible to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices may adversely affect the Company's financial condition, liquidity and results of operations. Lower prices also may reduce the amount of reserves that can be produced economically, as well as limit the ability to continue to exploit and develop the existing reserve base.
Forcenergy has utilized from time to time various financial instruments to hedge portions of its current oil and gas production to achieve more predictable cash flows and to reduce its exposure to fluctuations in oil and gas prices. The remaining portion of current production was not hedged so as to provide Forcenergy the opportunity to benefit from oil and natural gas price increases, should they occur. Specifically, Forcenergy utilized, from time to time, forward sales contracts and commodity swaps. All commodity hedging contracts were cancelled at the option of the counterparty as a result of the Company's filing under Chapter 11 of the U.S. Bankruptcy Code on March 21, 1999. Future hedging activities may be undertaken by the Company.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary financial information required to be filed under this item are presented on pages through of this Form 10-K, and are incorporated herein by reference.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CHANGES IN ACCOUNTANTS
None.
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
DIRECTORS
Messrs. Eric Forss, Robert Issal, Stig Wennerstrom and Bruce L. Burnham are currently directors of the Company.
Stig Wennerstrom, age 56, has been President and Chief Executive Officer and a director of the Company since its inception in September 1993. In March 1998 Mr. Wennerstrom was chosen to serve as Chairman of the Board of Directors of the Company. From 1982 until the formation of the Company, Mr. Wennerstrom was the President and Chief Executive Officer of the Company's predecessors.
Bruce L. Burnham, age 65, has served as a director of the Company since 1996. Mr. Burnham has served as President of The Burnham Group, a privately-held consulting and marketing firm formed by Mr. Burnham shortly after retiring from Dayton's Department Stores in 1984. From 1981 to 1984, Mr. Burnham served as Chairman and Chief Executive Officer of Dayton's Department Stores in Minneapolis, Minnesota. From 1979 to 1980, Mr. Burnham was President and Chief Executive Officer of Bonwit Teller in New York City. From 1978 to 1979, Mr. Burnham was President and Chief Operating Officer of Jordan Marsh. He serves on the Board of Directors of Paxson Communications Corporation, Financial Benefit Group, Inc. and J.B. Rudolph, Inc.
Eric Forss, age 33, has been a director of the Company since June 1994. Mr. Forss has served as Chief Executive Officer of Forsinvest AB, a private Swedish holding company and stockholder of the Company, since June 1998. Mr. Forss was also President of Forcenergy AB, a Swedish public corporation ("FAB") from May 1991 to June 1998 (on March 31, 1998, the Company acquired approximately 97% of the shares of FAB through a public exchange offer of Forcenergy Inc shares for the outstanding shares of FAB). Prior to serving as President of FAB, Mr. Forss was Vice President of FAB from May 1990 through April 1991. Mr. Forss served on the Board of Directors of FAB from May 1994 to March 1998.
Robert Issal, age 53, served as Chairman of the Board of Directors of the Company from May 1994 until March 1998 and has been a director since the Company's inception in September 1993. In March 1998 Mr. Issal was chosen to serve as Vice Chairman of the Board of Directors of the Company. Mr. Issal served as Chairman of FAB from May 1994 to June 1998 and served as Vice Chairman of FAB from April 1992 to April 1994. Mr. Issal served as President and Chief Executive Officer of Forsheda AB, a Swedish public company, from 1988 through 1991. From 1991 through 1994, Mr. Issal was the Chairman and President of Abstracta Group. Since 1994, Mr. Issal has served as Chairman and President of Rejmyre Belysning AB Sweden and its predecessor Rejmyre Light AB, a Swedish lighting manufacturer.
COMPENSATION ARRANGEMENTS FOR MEMBERS OF THE BOARD OF DIRECTORS
Fees paid Directors are in line with that paid by comparable companies. The fees are an annual retainer of $10,000 per year and $3,000 per meeting attended ($250 per telephonic meeting), capped at $25,000 per Director per year. In addition, prior to Mr. Wennerstrom being elected Chairman in March 1999, the Chairman of the Board of Directors received a fee of $3,000 per month. These fees are not paid to Directors who are employees of the Company. The Company also compensates Directors through the issuance of periodic stock option grants. These grants are made under the Company's Stock Option Plan typically on a formula basis. (See "Forcenergy Inc 1995 Stock Incentive Plan").
EXECUTIVE OFFICERS
The executive officers of the Company are Stig Wennerstrom, President and Chief Executive Officer and those officers listed below. Biographical information on Mr. Wennerstrom is included under the caption "Directors" above.
J. Russell Porter, age 37, is Executive Vice President. Prior to his promotion to Executive Vice President in July 1997, Mr. Porter served as Vice President - Corporate Development from October 1995 to June 1997 and as Vice President - Financial Planning & Analysis from April 1994 to October 1995. From January 1992 until joining the Company, Mr. Porter held the position of Vice President in the Natural Resources Group of Internationale Nederlanden (U.S.) Capital Corporation in New York. From July 1990 to December 1991, Mr. Porter was an Associate in the Energy Group of Manufacturers Hanover and Chemical Bank.
Gary Carlson, age 52, is Vice President - Alaska Division and has responsibility for all Alaskan operations. Prior to joining the Company in March 1997, Mr. Carlson held various positions during a tenure of 29 years with Unocal Corporation, most recently serving as Unocal's General Manager for Health, Environmental and Safety Support from 1995 until joining the Company. Mr. Carlson also served as President and Managing Director of Unocal Indonesia from 1992 to 1995 and as Managing Director for Unocal Netherlands N.V. from 1989 to 1992.
Robert G. Gerdes, age 42, is Vice President - Geoscience with responsibility for technical overview of company-wide geoscience, as well as technical evaluation of all drilling prospects and all acquisitions and new ventures. Prior to his promotion to Vice President - Geoscience in October 1997, Mr. Gerdes served as Geologist and Evaluations Manager from January 1994 to October 1997. Mr. Gerdes worked as an independent consulting geologist from September 1993 until joining the Company in January 1994. Mr. Gerdes served as Senior Geologist Corporate Staff for Graham Resources from August 1987 to September 1993. Prior to joining Graham Resources, Mr. Gerdes held various geological positions with Crescent Exploration Company and Unocal Corporation.
Thomas F. Getten, age 51, is Vice President, General Counsel and Secretary. Prior to joining the Company in January 1997, Mr. Getten was in private law practice in New Orleans. From January 1996 until joining the Company, Mr. Getten was a partner with Nesser, King & LeBlanc, a New Orleans law firm, and from May 1974 until December 1995, Mr. Getten was a partner and stockholder with Liskow & Lewis, also a New Orleans law firm.
E. Joseph Grady, age 46, is Vice President, Treasurer and Chief Financial Officer. From 1980 until joining the Company in October 1995, Mr. Grady held various financial management positions with Southdown, Inc. and its subsidiaries, including Pelto Oil Company from 1980 through 1989, serving as Vice President - Finance during 1988 and 1989. Most recently Mr. Grady was Director of Finance for Southdown Environmental Systems, Inc. from January 1991 until joining the Company.
Percy A. Payne, age 57, was Vice President - Gulf of Mexico Division and had responsibility for all Gulf of Mexico and Gulf coast operations until his resignation effective February 28, 1999. Prior to joining the Company in August 1996, Mr. Payne served as President of Payne Energy Associates, Inc., a privately held consulting group formed by Mr. Payne in September 1994 serving the international oil industry. Prior to establishing his consulting business, Mr. Payne held various positions during a tenure of 27 years with Shell Oil Company USA, most recently serving as Vice President of Pecten International, Shell Oil Company USA's international subsidiary. Mr. Payne also served as General Manager of Operations for the lower 48 states (excluding California) and Alaska for Shell Western E&P from April 1986 to September 1991.
Mark Yelverton, age 43, is Vice President - International Operations and is responsible for all international operational activities. Additionally, upon the resignation of Mr. Payne, Mr. Yelverton assumed responsibility for managing the drilling and production operations for the Gulf of Mexico Division. Mr. Yelverton joined the Company in April 1997 and served as Manager - - International Operations, until his promotion to his current position in October 1997. Before joining the Company, Mr. Yelverton served in various positions, culminating in an appointment as Director General for Phibro Energy (White Nights Joint Enterprise, Russia) from 1991 to 1997. Prior to joining Phibro, Mr. Yelverton was employed by Chevron Corporation serving in various petroleum engineering and geological positions.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Compensation Committee, consisting of Robert Issal and Bruce L. Burnham, believes that its policies are reflected in the Company's executive compensation program which aims to: (i) motivate executives toward effective long-term management of Company operations; (ii) reward effective, efficient ongoing management of Company operations; and (iii) provide the ability to attract and retain executives through competitive salary levels and benefit programs.
Executive Compensation. The Company's executive compensation program includes, separately or through any combination, base salary, annual incentives and various stock and stock option programs.
Base Salary and Annual Incentives. The Company's policy, as implemented by the Compensation Committee, is to compensate executives to reflect performance and be competitive in the market. The Compensation Committee considers the executive's individual performance and that of the Company as a whole along with other relevant factors in setting compensation, including discretionary bonuses. The Compensation Committee considers the scope of each executive's responsibilities in selecting the performance measures to apply to that executive's compensation, and does not apply any specific weight to any particular measure of performance. These criteria, the performance of the executive officers and the performance of the Company were considered in the determination of bonuses for 1998. Because of a difficult industry business environment during 1998, the Company failed to meet its performance goals, therefore no cash bonuses were paid to the executive officers for the 1998 year other than those contractually mandated under employment agreements.
Stock Options. The Company believes that stock options are important in motivating executives to increase long term shareholder value because the options focus executive attention on stock price as a measure of performance and align the executive's financial interests with those of the Company's stockholders. Accordingly, prior to the Company's Initial Public Offering in 1995, the Company adopted, with stockholder approval, the Forcenergy Inc 1995 Stock Incentive Plan. (See "Forcenergy Inc 1995 Stock Incentive Plan") The Compensation Committee administers the Forcenergy Inc 1995 Stock Incentive Plan and grants options to employees based on the performance of the employee and the Company and other relevant factors. Since the options vest over a number of years, they enhance the Company's ability to retain option holders and motivate them to take a long-term view of the Company's interests in their decisions.
Grants of options to executive officers during 1998 were made based upon individual efforts and performance.
Chief Executive Officer Compensation. Mr. Wennerstrom entered into an employment agreement with the Company as President and Chief Executive Officer for an initial term of three years effective September 14, 1993. See "Employment Agreement of Certain Executive Officers". In May 1995, the Company amended this employment agreement in connection with the Initial Public Offering and in recognition of the Company's rapid growth in financial performance. Mr. Wennerstrom's compensation for 1998 was limited to that provided for in his employment agreement.
Robert Issal
Bruce L. Burnham
SUMMARY COMPENSATION TABLE
The following table sets forth information concerning cash and non-cash compensation paid or accrued for services in all capacities to the Company during the three years ended December 31, 1998 for each of the five most highly compensated executive officers of the Company ("Named Officers"):
- -------------------
(1) Amounts exclude perquisites and other personal benefits because such compensation, if any, is included in All Other Compensation.
(2) Includes $71,373 in annual premiums paid by the Company for life insurance policies on the life of, and payable to a beneficiary selected by, Mr. Wennerstrom for 1995 through 1998. Also includes employer matching contributions of $2,375, $4,750 and $5,000 under the Company's 401(k) Plan for 1996, 1997 and 1998, respectively, and for other non-cash benefits of $17,596, $13,251 and $13,193 received in 1996, 1997 and 1998, respectively.
(3) Mr. Porter joined the Company in April 1994 as Vice President - Financial Planning and Analysis, was promoted to Vice President - Corporate Development in November 1995 and was promoted to his current position in July 1997.
(4) Represents employer matching contributions under the Company's 401(k) Plan.
(5) Mr. Getten joined the Company in his current position in January 1997.
(6) Includes $85,600 in relocation reimbursement and $4,750 in employer matching contributions under the Company's 401(k) Plan.
(7) Includes $55,320 in relocation reimbursement and $4,750 in employer matching contributions under the Company's 401(k) Plan.
(8) Mr. Carlson joined the Company in his current position in March 1997.
EMPLOYMENT AGREEMENTS OF CERTAIN EXECUTIVE OFFICERS
The following is a description of employment agreements between the Company and its executive officers as of December 31, 1998. Current employment agreements and payments to executive officers are currently subject to the approval of the Bankruptcy Court.
Chief Executive Officer. In connection with the formation of the Company, Mr. Wennerstrom and the Company entered into an employment agreement effective as of September 14, 1993, and amended as of May 18, 1995 (the "Employment Agreement") pursuant to which Mr. Wennerstrom serves as President and Chief Executive Officer of the Company.
Under the Employment Agreement, Mr. Wennerstrom is entitled to an annual salary and fixed bonus. Mr. Wennerstrom received an annual salary of $533,333, $566,664 and $600,000 for 1996, 1997 and 1998, respectively. Mr. Wennerstrom's salary is subject to annual cost of living increases. In addition, Mr. Wennerstrom was entitled to receive a $150,000 bonus for 1997 and for each subsequent year, provided that the Company may require him to return this bonus, or a portion thereof, for any year in which the Company fails to attain pre-determined cash flow targets. The Employment Agreement also provides that the Company will maintain certain life insurance policies on the life of Mr. Wennerstrom, payable to a beneficiary selected by Mr. Wennerstrom. The term of the Employment Agreement extends to December 31, 1998, automatically renewed annually thereafter until December 31, 2001 for "rolling" three-year periods that can be terminated upon 36 months' prior notice, provided that the term can be ended upon 12 months' notice given after January 1, 2002.
The Employment Agreement is subject to early termination by the Company for cause or upon the death or incapacity of Mr. Wennerstrom. The Employment Agreement is subject to early termination by Mr. Wennerstrom for cause. If the Employment Agreement is terminated without cause by the Company or with cause (including certain changes in control of the Company) by Mr. Wennerstrom, the Company is obligated to pay Mr. Wennerstrom a termination fee of three times the amount of Mr. Wennerstrom's annual includible compensation.
Other. The Company has entered into employment agreements with J. Russell Porter, E. Joseph Grady and Thomas F. Getten as of the end of 1998. These employment agreements are for "rolling" periods of one year, provided that the automatic annual renewal can be terminated upon 60 days written notice. If the employment agreement is terminated without cause by the Company, the Company is obligated to pay such officers a severance payment provided for in such employment agreement equal to two years base salary and in the case of certain changes in control two and one-half years base salary.
TAX DEDUCTIBILITY OF EXECUTIVE COMPENSATION
The Company is subject to U.S. tax legislation enacted in 1993 that could limit the deductibility of certain compensation payments to its executive officers. The Company believes that any compensation realized in connection with the exercise of stock options granted by the Company will continue to be deductible as performance-based compensation. The Compensation Committee will continue to monitor the impact of this legislation on the Company's compensation policies.
FORCENERGY INC 1995 STOCK INCENTIVE PLAN
In May 1997, pursuant to a vote of the Company's stockholders, the Company's three existing stock option plans were consolidated to form the Forcenergy Inc 1995 Stock Incentive Plan (the "Stock Option Plan"). The Stock Option Plan is intended to provide officers and key employees with an opportunity to acquire a proprietary interest in the Company and additional incentive and reward opportunities based on the profitable growth of the Company and to aid the Company in attracting and retaining outstanding personnel. The Stock Option Plan provides for the granting of options (either incentive stock options within the meaning of Section 422(b) of the Internal Revenue Code of 1986, as amended ("Code"), or non-qualified stock options), restricted stock awards, stock appreciation rights, performance awards, and phantom stock awards, or any combination thereof.
The Stock Option Plan is administered by the Compensation Committee, which is composed of at least two Directors who are "outside directors" within the meaning of Section 162(m) of the Code and "non-employee directors" within the meaning of Rule 16b-3 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). The Stock Option Plan was amended in May 1998, pursuant to a vote of the Company's stockholders at the 1998 Annual Meeting, to permit awards of up to an aggregate of 6,000,000 shares of Common Stock. As of December 31, 1998, 6,000,000 shares of Common Stock had an aggregate market value of $15.75 million. The number of, and in some cases, types of, shares covered by the Stock Option Plan are subject to adjustments in the event of stock dividends, stock splits and certain other events. As of December 31, 1998, options covering up to an aggregate of 3,637,441 shares of Common Stock were outstanding under the Stock Option Plan, and 2,121,293 options were available for future grants after December 31, 1998.
All employees and Directors of the Company are eligible to participate in the Stock Option Plan. The Compensation Committee has the power to determine which employees receive awards under the Stock Option Plan and the terms of each award, except that awards to non-employee Directors are made upon unanimous consent of the entire Board of Directors.
No more than 500,000 shares of Common Stock, subject to adjustments, may be subject to grants to any one employee in any one year under the Stock Option Plan. This limitation will be applied so that compensation realized from awards under the Stock Option Plan will qualify as "performance based" compensation for purposes of Section 162(m) of the Code.
Upon initial appointment to the Board, a non-employee Director typically receives options to buy 10,000 shares of Common Stock, vesting annually over three years subject to their continued service as a Director. Upon their re-election to the Board at subsequent annual meetings of stockholders, these Directors receive options to buy 5,000 shares of Common Stock, vesting in six months after such annual meeting. All of these options are exercisable at the fair market value of Common Stock at the date of grant, and expire 10 years after grant. Incentive stock options granted under the Stock Option Plan cannot be exercisable at less than the fair market value of Common Stock on the date of grant (subject to adjustments), nor for more than 10 years after grant, provided that options granted to a holder of securities representing more than 10% of the total combined voting power of all classes of the Company's stock or of its subsidiary cannot be exercisable at less than 110% of the fair market value of Common Stock at the date of grant (subject to adjustments) or for longer than five years from grant. The Committee can determine how the exercise price of options will be paid. The Board of Directors may also grant options on a discretionary basis to individual directors.
The Compensation Committee has the authority, in its discretion, to amend the Stock Option Plan, unless approval of the Company's stockholders is required for the Stock Option Plan to meet the stockholder approval requirements of Sections 422 and 162(m) of the Code. Therefore, the Company's stockholders would need to approve any amendment that is "material" for purposes of Section 162(m) or required by Section 422, including any amendment (a) increasing the number of shares available in the aggregate for awards, (b) increasing the number of shares that may be granted to an employee, or (c) changing eligibility requirements for participation in the Stock Option Plan.
No grants of Restricted Stock Awards, Stock Appreciation Rights, Performance Awards or Phantom Stock Awards have been made under the Stock Option Plan. See "Stock Option Grants in 1998".
401(K) PLAN
The Company has adopted a 401(k) Profit Sharing Plan (the "401(k) Plan") for its employees. Under the 401(k) Plan, eligible employees are permitted to defer receipt of up to 15% of their cash compensation (subject to certain limitations imposed under the Code). The 401(k) Plan provides that a discretionary match of employee deferrals may be made by the Company in cash. Pursuant to the 401(k) Plan, the Company has currently elected to match $.50 for each $1.00 contributed by the employee through salary deferral, said deferral not to exceed 5% of an employee's salary, subject to limitations imposed by the Internal Revenue Service. The amounts held under the 401(k) Plan are invested among various investment funds maintained under the 401(k) Plan in accordance with the directions of each participant. Salary deferral contributions under the 401(k) Plan are 100% vested. Matching contributions vest immediately upon a participants attainment of a minimum of one year of service with the Company. Participants or their beneficiaries are entitled to payment of vested benefits upon termination of employment.
EMPLOYEE STOCK PURCHASE PLAN
The Company has adopted the Forcenergy Gas Exploration, Inc. Employee Stock Purchase Plan (the "Stock Purchase Plan"), which permits all Company employees (other than the Chief Executive Officer) who work full time (or part time for at least 20 hours per week and more than five months per year) to acquire Common Stock at a minor discount from its fair market value through payroll deductions.
For each six-month period beginning on January 1 or July 1 during the term of the Stock Purchase Plan, unless the Board determines otherwise, the Company will offer to each eligible employee the opportunity to purchase Common Stock. Employees may elect to participate prior to the start of a period and may elect to have from two to ten percent of their compensation withheld. The Stock Purchase Plan allows withdrawals, termination and changes in the level of participation. The purchase price will be 85% of the lesser of the fair market value of Common Stock on (i) the first day of the period or (ii) the last day of the period. No employee may purchase Common Stock under the Stock Purchase Plan valued at more than $25,000 (or such other maximum as may be prescribed from time to time under the Code) for each calendar year in accordance with the provisions of the Code.
Up to 100,000 shares of Common Stock are currently authorized for purchase under the Stock Purchase Plan. Employees purchased 50,866 shares of Common Stock under the Stock Purchase Plan during 1998 thereby resulting in all 100,000 shares of Common Stock authorized for purchases under the Stock Purchase Plan having been purchased. No additional shares of Common Stock are currently available for purchase under the Stock Purchase Plan unless additional shares are authorized by the Stockholders for purchase under the Stock Purchase Plan.
STOCK PRICE PERFORMANCE INCENTIVE PLAN FOR EMPLOYEES OF THE COMPANY
Effective January 1, 1997, the Company adopted the 1997 Stock Price Performance Incentive Plan for Employees of the Company (the "$60 a Share Plan" or "Plan"). All of the Company's employees are eligible to receive awards of the Company's Common Stock under the Plan without being required to pay any purchase price if (1) the closing price of the Company's Common Stock reaches $60 a share before January 1, 2000, and (2) the employee remains employed by the Company through the date that the shares are actually distributed under the Plan. If the Common Stock reaches $60 per share on any date (the "$60 Price Date") on or before December 31, 1999, then all employees would receive Common Stock worth 500% of their annual base compensation, distributed in equal installments on the first, second and third anniversaries of the $60 Price Date, if they are still employed by the Company. For purposes of determining the value of Common Stock to be distributed, the Common Stock will be valued at its closing price on the $60 Price Date. The Plan also provides for reduced compensation if the Common Stock does not reach $60 a share during the plan period but does reach $50 a share (but not $60) prior to December 31, 1999 (with December 31, 1999 representing the "$50 Price Date"). In such case, all employees would receive Common Stock worth 250% of their annual base compensation, distributed in equal installments on December 31, 2000, 2001 and 2002.
The Compensation Committee of the Company's Board of Directors administers the Plan. The Compensation Committee has the sole and exclusive right to interpret and administer the Plan, including determining the employees
eligible to receive awards under the Plan, calculating the employees' annual base pay and the number of shares of Common Stock issuable and reducing the number of shares issuable to particular employees.
The Plan is intended to qualify under Section 162 (m) of the Code so that the Company may deduct the value of the shares issuable under the Plan regardless of the amount thereof. Therefore, changes to the Plan will require stockholder approval if they are "material" for purposes of Section 162(m) of the Code. "Material" changes would include an increase in the aggregate number of shares issuable under the Plan or to a particular employee or a change in the eligibility criteria for participation in the Plan.
STOCK OPTION GRANTS IN 1998
There were no options exercised by a Named Officer in 1998.
- ---------------------
(1) Potential realizable value was reported net of the option exercise price, but before taxes, associated with the exercise. These amounts represent the theoretical realizable value on the option expiration date, assuming that the stock price appreciates annually at the rates shown from the date of grant through expiration. Actual values realized, if any, on stock option exercises are dependent on the future performance of the Common Stock and the officer's continued employment throughout the vesting period. Accordingly, the amounts reflected in this table may not necessarily be achieved. All options granted to the Named Officers in 1998 reflected the market price of the common stock on the date of grant.
(2) Options were granted to Mr. Getten on January 22, 1998 under the Stock Option Plan and such options vest 33.33% on each of the third through fifth anniversaries of the date of grant.
- ----------- (1) Value based on the last trade on the New York Stock Exchange on December 31, 1998 ($2.625 per share), less the applicable exercise price of the outstanding options.
Pursuant to a repricing of stock options held by non-executives of the Company on March 4, 1998, options held by Mr. Robert Gerdes, a Vice President of the Company, to purchase 20,000 shares at $26.875 per share were canceled and replaced with new options to purchase 18,186 shares at $22.00 per share. On the same date, options held by Mr. Mark Yelverton, a Vice President of the Company, to purchase 25,700 shares at $30.50 per share were canceled and replaced with new options to purchase 22,124 shares at $22.00 per share. The options repriced were options granted to each prior to their promotion to their positions as an officer of the Company. In both cases, the exercise price of each newly issued option represents the market price of the common stock on the date of grant and the vesting provisions are consistent with the original grant. The original remaining option terms at the date of repricing were 7 years and 302 days and 9 years and 55 days in the cases of Mr. Gerdes and Mr. Yelverton, respectively.
In January 1999 the Board of Directors authorized a repricing of stock options held by all optionholders of the Company. This was deemed necessary because of the precipitous decline in the Company's stock price and the need to maintain the incentive nature of the option plan. On February 1, 1999, all stock options currently outstanding were cancelled and reissued with an exercise price of $1.275 per share (the fair market value of the stock on that date plus 20%). All other terms of options previously granted to non-executives remained unchanged. The number of options held by executives and directors was reduced by approximately 114,000 shares.
STOCK PERFORMANCE GRAPH
The following graph compares total return of the Company's Common Stock against the S&P 500 Index and a peer group index consisting of public independent oil and gas companies.* The graph assumes that $100 was invested on August 2, 1995 (the date of the closing of the Initial Public Offering) in the Company's Common Stock, the S&P 500 Index and the peer group and that dividends thereon were reinvested quarterly.
[CHART: COMPARE CUMULATIVE TOTAL RETURN AMONG FORCENERGY INC, S&P 500 INDEX AND PEER GROUP INDEX]
*The peer group consists of Ocean Energy Inc., Hugoton Energy Inc., Louis Dreyfus natural Gas Company, Inc., Newfield Exploration Company, PetroCorp, Inc. and Stone Energy Corp. Hugoton Energy Inc. was acquired by Chesapeake Energy Corporation in March 1998.
ITEM 12.
ITEM 12. BENEFICIAL OWNERSHIP OF COMMON STOCK
The following table is furnished as of March 31, 1999 to indicate beneficial ownership of shares of the Common Stock by persons owning more than 5% of the Common Stock and all executive officers and Directors individually and the executive officers and Directors as a group. The information in the following table is provided by such persons.
* Less than 1%
- ------------------ (1) Except as otherwise noted, each stockholder has sole voting and investment power with respect to the shares beneficially owned. (2) Represent shares of Common Stock issuable pursuant to stock option grants that are vested or that will be vested within 60 days of the effective date of this schedule. (3) The address of Forsinvest AB and Stridor Invest AB and Messrs. Forss and Issal is Birger Jarlsgatan, 73-75, Box 19040, S-10432 Stockholm, Sweden. The address of Messrs. Wennerstrom, Porter, Getten and Grady is 2730 SW 3rd Avenue, Suite 800, Miami, Florida 33129. The address of Mr. Burnham is 10 Haig Point Circle, Hilton Head, SC 29938. The address of Messrs. Gerdes, Payne and Yelverton is 3838 N. Causeway Boulevard, Lakeway Three, Suite 2300, Metairie, Louisiana 77002. The address of Mr. Carlson is 310 K Street, Suite 700, Anchorage, Alaska 99501. (4) Of the shares listed as beneficially owned by Mr. Wennerstrom, 4,000 shares are owned by each of his children, Linda Wennerstrom and Henrik Wennerstrom, for which Mr. Wennerstrom disclaims beneficial ownership. (5) Of the shares beneficially owned by Mr. Porter, 1,000 shares are owned by his wife, Deborah A. Porter. (6) Of the shares beneficially owned by Mr. Carlson, 4,600 shares are owned in trust for his children: Jurdis Carlson (1,400 shares), Nathan Carlson (600 shares), Amanda Carlson (600 shares), Gary Carlson (1,000 shares) and Rachael Carlson (1,000 shares). (7) Of the shares beneficially owned by Mr. Gerdes, 1,000 shares are owned by each of his children, Julie Gerdes and Caroline Gerdes. (8) Includes 1,635,495 shares owned by Forsinvest AB (the "Forss Affiliates") acquired in connection with the Company's public tender offer for FAB hereinafter described (See "Certain Relationships and Related Transactions"). Eric Forss served as one of the directors of , Forsinvest AB . Although Mr. Forss may be deemed to share investment control over securities held by the Forss Affiliates, Mr. Forss only had a pecuniary interest in the Forss Affiliates and their portfolio securities of only approximately 10%. (9) In connection with the public tender offer hereinafter described (See "Certain Relationships and Related Transactions"), Eric Forss, Forsinvest AB and Stridor Invest AB acquired 1,942,180 shares of Common Stock. Eric Forss is an owner, or empowered officer of Forsinvest AB and Stridor Invest AB. The shares of Common Stock held by Forsinvest AB and Stridor Invest AB are also included in the holdings of Eric Forss.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company is currently a party to or has engaged in the following transactions with its directors, officers and principal stockholders.
The Company leases its principal offices in Miami, Florida from an affiliate of the Forss family. The terms of the lease include current monthly payments of approximately $23,000, expiring in October 2001. The Company made payments under such lease of $292,000 in 1997 and $300,000 in 1998. The Company believes that the lease terms are comparable to those terms which could be obtained from an unaffiliated third party.
In connection with Mr. Wennerstrom's currently outstanding stock options, the Company has granted certain piggyback registration rights and a put option on the value of all such options and the Common Stock acquired through the exercise of such options.
The Company has a consulting arrangement with Wictor Forss, the former Chairman of the Board of the Company, whereby Mr. Forss receives $10,000 per month in exchange for consulting services. The Company believes that Mr. Forss' prior years of service to the Company as a Director enable him to provide business and financial advice to the Company at a reasonable cost. This consulting arrangement with Wictor Forss terminated March 31, 1999.
In July 1997 the Company loaned J. Russell Porter, its Executive Vice President, $200,000 pursuant to the terms of a promissory note executed and delivered by Mr. Porter to the Company. The promissory note bears interest at 9% per annum and is payable upon demand. Mr. Porter granted the Company a security interest in the stock options granted to him pursuant to the Stock Option Plan. As of March 31, 1999 the outstanding principal and accrued interest balance under the promissory note was $92,443.
On December 19, 1997, the Company made a public stock-for-stock tender offer for all of the outstanding shares of Forcenergy AB ("FAB"). FAB was a Swedish public company that at the time of the tender offer owned approximately 34% of the outstanding Common Stock of the Company. Eric Forss, Director of the Company, was President of FAB and directly or through indirect affiliations owned approximately 22% of the equity interest and 52% of the voting interest in FAB. As of December , 1998, more than 99% of the outstanding common shares of FAB were tendered in connection with the tender offer. The Company issued approximately 7.9 million shares pursuant to the tender offer, including 1,904,560 shares to Forsinvest AB and 21,436 to Stridor Invest AB, companies in which the Forss Affiliates owned a majority interest.
The Company entered into a registration rights agreement with Eric Forss and the Forss Affiliates in order to give Eric Forss and the Forss Affiliates a demand right to require the Company to register all or part of the shares of Common Stock received by Eric Forss and the Forss Affiliates in connection with the tender offer under the Securities Act of 1933 as amended (the "Securities Act"), unless (i) exemption for such proposed sale exists under the Securities Act or (ii) the Company has given notice of its intention to file a registration statement. The Company also granted Eric Forss and the Forss Affiliates piggyback registration rights in any offering by the Company of any of its securities to the public except a registration statement on Forms S-4 or S-8. The Company also agreed to bear the expenses of all such registrations.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) DOCUMENTS INCLUDED IN THIS REPORT:
2. FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's financial statements and related notes.
3. A. EXHIBITS:
* Filed herewith. All other exhibits have been previously filed.
B. REPORTS ON FORM 8-K
On November 17, 1998, the Company filed a Current Report on Form 8-K reporting that the Company had entered into a Stock Purchase Agreement with certain prospective purchasers.
GLOSSARY OF OIL AND GAS TERMS
The definitions set forth below shall apply to the indicated terms as used herein. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
BOPD. Barrels of oil per day.
BOE. Barrel of oil equivalent.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Discounted Present Value. A method of determining the present value of proved reserves. Under the SEC method, the future net revenues before income taxes from proved reserves are estimated assuming that oil and natural gas prices and production costs remain constant. The resulting stream of revenues is then discounted at the rate of 10% per year to obtain the present value.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
Farm-in or farm-out. An agreement whereupon the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out."
Field. An area consisting of single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per day.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MCFPD. One million cubic feet per day.
Mmcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
Oil. Crude oil and condensate.
Present value. When used with respect to oil and gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.
Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.
Proved reserves. 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.
Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required from recompletion.
Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of costs of production.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
Updip. A higher point in the reservoir.
Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
Workover. Operations on a producing well to restore or increase production.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
FORCENERGY INC
Dated: By: ---------------------------------------- E. Joseph Grady Vice President - Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated:
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1998
FORCENERGY INC
MIAMI, FLORIDA
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of Forcenergy Inc (Debtor-in-Possession)
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders equity (deficit) and cash flows present fairly, in all material respects, the financial position of Forcenergy Inc (Debtor-in-Possession) (the "Company") at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 1 to the financial statements, the Company has filed voluntarily under Chapter 11 of the U.S. Bankruptcy Code and has incurred significant losses from operations in 1998 and 1997. These matters raise substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Miami, Florida March 21, 1999
FORCENERGY INC (DEBTOR-IN-POSSESSION) CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these financial statements.
FORCENERGY INC (DEBTOR-IN-POSSESSION) CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these financial statements.
FORCENERGY INC (DEBTOR-IN-POSSESSION) CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
The accompanying notes are an integral part of these financial statements.
FORCENERGY INC (DEBTOR-IN-POSSESSION) CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Forcenergy Inc, formerly Forcenergy Gas Exploration, Inc., a Delaware Corporation, and its subsidiaries ("Forcenergy" or the "Company"), is an independent oil and gas company engaged in the exploration, acquisition, development, exploitation and production of oil and natural gas properties.
As an independent oil and gas producer, the Company's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas and oil and condensate, which are dependent upon numerous factors beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, as evidenced by the recent volatility of oil and gas prices, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on the Company's financial position, results of operations, quantities of oil and gas reserves that may be economically produced and access to capital.
CHAPTER 11 FILING AND LIQUIDITY
On March 21, 1999, the Company and its wholly-owned subsidiary, Forcenergy Resources Inc., filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to facilitate the restructuring of the Company's long-term debt, revolving credit, trade and other obligations. The filing was made in the U.S. District Court for the Eastern District of Louisiana in New Orleans (the "Bankruptcy Court"). The Company continues to operate as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders. The bankruptcy petitions were filed in order to preserve cash and to give the Company the opportunity to restructure its debt. The consummation of a plan of reorganization is the primary objective of the Company. The plan of reorganization will set forth the means for satisfying claims, including liabilities subject to compromise, and interests in the Company. A plan of reorganization may result in, among other things, material dilution or elimination of existing security holders as a result of the issuance of securities to creditors or new investors. The consummation of a plan of reorganization will require approval of the Bankruptcy Court.
At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect on the business of the Company or on the interests of creditors, royalty owners or stockholders. As a result of the bankruptcy filing, all of the Company's liabilities, including certain secured debt, are subject to compromise.
The accompanying financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of the bankruptcy filing and related events, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. In addition, a plan of reorganization, or rejection thereof, could change the amounts reported in the financial statements. As a result, there is substantial doubt about the Company's ability to continue as a going concern. The ability of the Company to continue as a going concern is dependent upon confirmation of a plan of reorganization, adequate sources of capital and the ability to sustain positive results of operations and cash flows sufficient to continue to explore for and develop oil and gas reserves.
In the ordinary course of business, the Company makes substantial capital expenditures for the exploration and development of oil and natural gas reserves. Historically, the Company has financed its capital expenditures, debt service and working capital requirements with cash flow from operations, public offerings of equity, private offerings of debt, asset sales, a senior credit facility and other financings. Cash flow from operations is sensitive to the prices the Company receives for its oil and natural gas. A reduction in planned capital spending or an extended
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
decline in oil and gas prices could result in less than anticipated cash flow from operations in the current fiscal year and in later years which could have a material adverse effect on the Company.
Management's plans are to continue to incur capital expenditures with the goal of increasing production and reserves. To finance these planned capital expenditures, the Company will be required to supplement its anticipated cash flow from operations with a combination of asset sales, financings or other capital-raising transactions. The ability to incur capital expenditures, sell properties and obtain additional financing is subject to the approval and ongoing supervision of the Bankruptcy Court. There is no assurance that adequate funds can be obtained on a timely basis or that the Bankruptcy Court will approve such transactions.
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of Forcenergy Inc, and it's subsidiaries after elimination of all intercompany transactions and balances.
ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from those estimates.
CASH/CASH EQUIVALENTS
The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. The Company maintains cash deposits with several financial institutions. At certain times, these deposits may exceed federally insured limits.
ACCOUNTS RECEIVABLE
Accounts receivable relate primarily to sales of oil and gas production and amounts due from joint interest partners for expenditures made by the Company on behalf of such partners. The Company reviews the financial condition of potential purchasers and partners prior to signing sales or joint interest agreements. At December 31, 1998 and 1997, the allowance for doubtful accounts was $1,999,000 and $400,000, respectively. The Company requires certain forms of financial assurance from its most significant customers.
OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for oil and gas properties whereby all productive and non-productive exploration, development and acquisition costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. No gains or losses are recognized upon the sale or other disposition of oil and gas properties, except in unusually significant transactions.
Depreciation, depletion and amortization of oil and gas properties are computed on a composite unit-of-production method based on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development, restoration, dismantlement and abandonment costs associated therewith, are included in the computation base. The Company evaluates all unevaluated oil and gas properties on a quarterly basis to determine if any impairment has occurred or if the property has been otherwise evaluated. If a property has been evaluated, or if there is determined to be any impairment, costs related to the particular unevaluated properties are reclassified as an evaluated oil and gas property, and thus subject to amortization if there are proved reserves associated
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
with the related cost center. Otherwise, such impairment will be recognized in the period in which it occurs.
Under the Securities and Exchange Commission's full cost accounting rules, the Company reviews the carrying value of its oil and gas properties each quarter. Under full cost accounting rules, capitalized costs of oil and gas properties, net of deferred tax reserves, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. Application of this rule generally requires pricing future production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and requires a permanent write-down of capitalized costs if the "ceiling" is exceeded, even if prices declined for only a short period of time.
During the fourth quarter of 1998 and 1997 the Company recognized a non-cash impairment of recorded oil and gas assets amounting to $275 million and $200 million ($162.8 million after tax), respectively, pursuant to the above discussed "ceiling test" provisions.
The majority of the Company's oil and gas properties are located in the Gulf of Mexico and Cook Inlet, Alaska.
DEFERRED FINANCING COSTS
Deferred financing costs are amortized over the terms of the related debt and amounted to $10,879,000 and $12,084,000 as of December 31, 1998 and 1997, respectively.
REVENUE RECOGNITION
Revenues from oil and natural gas production are recorded using the sales method, net of royalties and net profit interests. When the Company's share of sales volumes differ from the Company's entitled share of production based on the net revenue interest attributable to its working interest, an imbalance occurs. Under the sales method of revenue recognition, the net over/under-produced volumes are not recorded as a liability, or receivable, respectively. The under-produced party later takes sales volumes in excess of its entitled share of future production to eliminate the imbalance. To the extent an imbalance exceeds the remaining estimated proved oil and natural gas reserves for a given property, the Company records a liability or a receivable, as appropriate. At December 31, 1998, the Company's net imbalance position was not material.
During 1998, 1997 and 1996 the Company maintained a hedging program on a portion of its estimated future production to provide a certain minimum level of cash flow from its sales of crude oil and natural gas (see Note 8). Any hedging gains or losses under these contracts are recognized in revenue upon monthly settlement of hedged production. All commodity price hedging contracts in place at December 31, 1998 were cancelled at the option of the counterparties subsequent to the aforementioned Chapter 11 bankruptcy filing (see Note 8).
STOCK-BASED COMPENSATION
Statement of Financial Accounting Standards No. 123 "Accounting for Stock-Based Compensation," ("SFAS No.123") encourages, but does not require companies to record compensation costs for stock-based employee compensation plans at fair value. The Company has chosen to continue to account for stock-based employee compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Accordingly, compensation cost for stock options, awards and warrants is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock (see Note 6).
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
INCOME TAXES
The Company follows the asset and liability approach to account for income taxes. Under this method, deferred taxes are recognized for temporary differences between the book and tax basis of assets and liabilities. These temporary differences are measured using applicable enacted tax rates and provisions of enacted tax laws.
EARNINGS PER SHARE
During 1997 the Company adopted Statement of Financial Accounting Standards No. 128 "Earnings Per Share" ("SFAS No. 128") and has restated all years presented in accordance therewith. SFAS No. 128 requires a dual presentation of basic and diluted earnings per share ("EPS") on the face of the statement of operations. Basic EPS is computed by dividing income available to common stockholders by the weighted-average number of common shares for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in earnings (see Note 7).
ENVIRONMENTAL EXPENDITURES
Environmental expenditures relating to current operations are expensed or capitalized, as appropriate, depending on whether such expenditures provide future economic benefits. Liabilities are recognized when the expenditures are considered probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition coincides with the Company's commitment to a formal plan of action.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company includes fair value information in the Notes to Consolidated Financial Statements when the fair value of its financial instruments can be determined and is different from the book value. The Company generally assumes the book value of those financial instruments that are classified as current approximate fair value because of the short maturity of these instruments. For non-current financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments. Due to the bankruptcy filing (see Note 1), the Company is uncertain as to the timing and amount of liquidation or settlement of liabilities subject to compromise. Accordingly, except for debt which has quoted market prices, the Company does not believe it is practicable to estimate the fair value of those liabilities.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board (the "FASB") issued Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"). The statement requires companies to report the fair market value of derivatives on the balance sheet and record in income or other comprehensive income, as appropriate, any changes in the fair value of the derivative. Statement No. 133 will become effective with respect to the Company on January 1, 2000. Management has not determined the effect, if any, of adopting SFAS No. 133.
RECLASSIFICATIONS
Certain reclassifications have been made to the Company's financial statements to conform them to classifications between years.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 -- ACQUISITIONS AND MERGERS
1998 ACQUISITIONS
The Company completed several acquisitions during 1998 at an aggregate cost of approximately $54.0 million. The aggregate effect of these acquisitions on the results of operations of the Company for the periods presented was not material.
1997 ACQUISITIONS
The Company completed several acquisitions during 1997 at an aggregate cost of approximately $220.5 million. The three most significant acquisitions, all of which were accounted for as purchases, are discussed below, including pro forma results of operations for the Company assuming the acquisitions had been completed on January 1, 1996. The aggregate effect of other acquisitions on the results of operations of the Company for the periods presented was not material.
On January 21, 1997, Forcenergy acquired all of the outstanding stock of Great Western Resources, Inc. ("Great Western") for approximately $48.3 million. The net assets acquired consisted primarily of producing oil and gas properties. The results of operations of the acquired properties are included in the Company's results of operations beginning January 21, 1997.
On June 4, 1997, Forcenergy acquired a 97.75% working interest in certain oil and gas properties located in the Cook Inlet, Alaska from Stewart Petroleum Company ("Stewart") for $18.7 million and assumed operations of the field. The results of operations for the acquired properties are included in the Company's operations beginning June 4, 1997. In October 1997 the Company increased it's interest in this field to 100%.
On October 22, 1997, Forcenergy, in separate transactions, acquired all of the outstanding common stock of Edisto Resources Corporation ("Edisto") and Convest Energy Corporation ("Convest"). Forcenergy issued approximately 2.8 million shares of common stock valued at $34.96 per share, or approximately $98.9 million. The shareholders of Edisto also received $69.3 million in cash from balances Forcenergy received in the merger. Edisto owned 73% of the outstanding common stock of Convest. The net assets acquired consisted principally of producing oil and gas properties. The results of operations of the acquired properties are included in the Company's operations beginning October 22, 1997.
1996 ACQUISITIONS
The Company completed several acquisitions during 1996 at an aggregate cost of approximately $148.0 million. The two most significant acquisitions are discussed below, including pro forma results of operations for the Company assuming the acquisitions had been completed on January 1, 1995. The aggregate effect of other acquisitions on the results of operations of the Company for the periods presented was not material.
On June 28, 1996, the Company acquired certain producing oil and gas leasehold interest and related equipment from Amerada Hess Corporation ("Amerada Hess") for a net cash consideration of $6.9 million. The acquisition has been accounted for as a purchase and the results of operations of the properties acquired are included in the Company's results of operations effective June 28, 1996.
On December 30, 1996, the Company acquired Marathon Oil Company's interests in certain crude oil properties in the Cook Inlet area and Prudhoe Bay Unit, Alaska ("Marathon") for a net cash consideration of $107.8 million. The acquisition has been accounted for as a purchase and the results of operations of the properties acquired are included in the Company's results of operations effective December 30, 1996.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following pro forma statements of operations have been prepared to give effect to the Great Western, Stewart, Edisto, Convest, Amerada Hess, Marathon, Conoco and Ashlawn acquisitions as if they had occurred on January 1, 1996. The historical results of operations have been adjusted to reflect (i) revenues and expenses attributable to the properties, (ii) the difference between the properties' historical depletion, depreciation, and amortization and such expense calculated based on the value allocated to the acquired assets, (iii) the increase in interest expense associated with the debt incurred, and (iv) the increase in income taxes giving retroactive effect to the transactions. Management does not believe the pro forma amounts purport to be indicative of the results of operations that would have been reported had the acquisitions occurred at the dates indicated below or that may be reported in the future (in thousands, except per share amounts).
FORCENERGY AB ACQUISITION
On December 19, 1997 Forcenergy made a public tender offer for all of the outstanding shares of FAB. FAB was formed in 1990 to provide capital for Forcenergy's oil and gas operations in the United States and currently owns 8,740,486 shares of Forcenergy common stock, its only significant asset. The proposed issuance of the Forcenergy shares pursuant to the terms of the tender offer was approved by Forcenergy Inc shareholder vote on March 17, 1998. On March 31, 1998, 97% of the outstanding common shares of FAB had been tendered in connection with the offer and all conditions of the offer were met. As of December 1998, 99.3% of the outstanding FAB shares had been tendered and Forcenergy had issued approximately 7.9 million shares valued at $27 per share (the price of the Company's common stock on the date the tender offer was initiated) in exchange for the tendered shares. The 8,740,486 Forcenergy shares owned by FAB are controlled by Forcenergy, and for accounting and voting purposes are no longer considered outstanding. The acquisition has been accounted for as a purchase with results of operations included beginning March 31, 1998.
NOTE 3 -- PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment were as follows at December 31, 1998 and 1997:
Depletion, depreciation, and amortization for the years ended December 31, 1998, 1997 and 1996 was, $420.9 million including a $275 million impairment (See Note 1), $313.3 million including a $200 million impairment (see Note 1) and $58.5 million, respectively. Depletion, depreciation and amortization rates per BOE of hydrocarbons produced (using a Mcf-to-Bbl conversion factor of 6 to 1) for the years ended December 31, 1998, 1997 and 1996 were
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
$6.84 (exclusive of impairment), $6.36 (exclusive of impairment) and $6.18, respectively.
Included in property, plant and equipment are capitalized internal costs relating to oil and gas property acquisition, exploration and development costs of $10.2 million, $7.9 million and $2.3 million for the years ended December 31, 1998, 1997 and 1996, respectively.
During the years ended December 31, 1998, 1997 and 1996 the Company capitalized interest of $4.4 million, $4.2 million, and $2.2 million, respectively, on expenditures made in connection with exploration and development projects on significant unproved properties that are not subject to current depletion, depreciation or amortization. Interest is capitalized only for the period that activities to bring the properties to their intended use are ongoing.
The following sets forth the composition of capitalized costs excluded from the depletion, depreciation, and amortization base at December 31, 1998, 1997 and 1996:
At December 31, 1998, approximately 37% of excluded costs relate to offshore activities in the Gulf of Mexico, 34% relate to offshore activities in Alaska and the remainder relates to domestic onshore and international activities. The inclusion of these costs in the depletion, depreciation and amortization computation will be at the point in time that it is determined, through drilling activities, that proved reserves do or do not exist on the applicable properties, typically within three to five years.
NOTE 4 -- DEBT
As described in Note 1 and below, because of the Company's filing of Chapter 11, all amounts are subject to compromise as of December 31, 1998.
SENIOR CREDIT FACILITY
During 1997 the Company's Senior Credit Facility (the "Facility") was amended to reduce the borrowing rates under the Facility, to extend the term of the Facility and to revise various administrative provisions of the Facility. Specifically, during 1997, advances under the Facility bore interest at either the prime rate or LIBOR plus 1.0%, at the election of the Company. The amendment also provided for borrowings on a revolving basis through January 1, 1999, at which time the amounts outstanding would have converted to a term loan with quarterly payments of principal and accrued interest through June 30, 2002.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
During 1998 the Company renegotiated, and subsequently amended, the Facility to increase both the maximum loan amount and the borrowing base to $320 million with subsequent decreases to $300 million on May 1, 1999 and to $275 million on September 1, 1999. The Facility provides for borrowings on a revolving basis through March 31, 2002 at which time all outstanding amounts under the Facility become due and payable. Advances under the Facility bear interest at either the prime rate or a Fixed Rate (as defined in the Facility agreement), at the election of the Company. Commitment fees on the unused portion of the facility are due quarterly at an annual rate between .375% and 0.5%.
The borrowing base is subject to redetermination semi-annually based on revised reserve estimates. The loan is collateralized by substantially all of the Company's oil and gas properties.
At December 31, 1998 the Company had drawn down $296.7 million under the Facility and an additional $5.5 million of availability was utilized for outstanding letters of credit issued under the Facility. The Company had availability under the Facility of $17.8 million at December 31, 1998.
The Facility contains certain covenants which include maintenance of a minimum tangible net worth, certain financial ratios, restrictions on asset sales, affiliated transactions and compensation and certain limitations on dividends and additional debt or liens. The Company was in violation of several of the financial covenants as of December 31, 1998.
9 1/2% NOTES
On November 6, 1996, the Company issued an aggregate principal amount of $175 million of 9 1/2% Senior Subordinated Notes (the "9 1/2% Notes") which mature on November 1, 2006. The 9 1/2% Notes were issued under an Indenture (the "9 1/2% Notes Indenture") which provides that interest is payable semiannually, in arrears, on May 1 and November 1 of each year, commencing May 1, 1997, with principal due at maturity.
The 9 1/2% Notes are redeemable in whole or in part at the option of the Company, at any time on or after November 1, 2001, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, thereon.
Prior to November 1, 2001, the Company may redeem the 9 1/2% Notes, in whole or in part, at the Make-Whole Price, plus accrued and unpaid interest, if any, through the date of redemption. The Make-Whole Price is defined as the greater of (i) the sum of the outstanding principal amount and Make-Whole Amount (defined below) of such 9 1/2% Notes, and (ii) the redemption price of such 9 1/2% Notes on November 1, 2001, determined pursuant to the Indenture (104.75% of the principal amount). The Make-Whole Amount is defined as the excess, if any, of (i) the present value of the remaining interest premium and principal payments due on such 9 1/2% Notes as if such 9 1/2% Notes were redeemed on November 1, 2001, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (ii) the outstanding principal amount of such 9 1/2% Notes. In addition, during the first 36 months after October 31, 1996, the Company may redeem up to $61.25 million in aggregate principal amount of the 9 1/2% Notes at a redemption price of 109.5% of the principal amount thereof plus accrued and unpaid interest, if any, thereon to the redemption date with the net proceeds of an offering of common equity; provided that at least $113.75 million in aggregate principal amount of the 9 1/2% Notes remain outstanding immediately after the occurrence of such redemption.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The 9 1/2% Notes holders may, at their election, require that the Company prepay the 9 1/2% Notes upon the occurrence of a "change of control" as defined in the 9 1/2% Notes Indenture. Upon a "change of control", the holders may require the Company to repurchase all or any part of the 9 1/2% Notes at a repurchase price equal to 101% of the aggregate principal amount thereof plus accrued and unpaid interest, if any, thereon. Furthermore, under certain circumstances, the Company may become obligated to offer to purchase all or a portion of the 9 1/2% Notes at 100% of the principal amount thereof, together with accrued and unpaid interest, if any, with the net proceeds of certain asset sales.
8 1/2% NOtes
On February 14, 1997, the Company issued an aggregate principal amount of $200 million in 8 1/2% Senior Subordinated Notes priced at $99.338, with an effective yield to maturity of 8.6% (the 8 1/2% Notes), which mature on February 15, 2007. The 8 1/2% Notes were issued under an Indenture (the "8 1/2% Notes Indenture") which provides that interest on the 8 1/2% Notes will be payable in cash in arrears semiannually on February 15 and August 15 of each year, commencing August 15, 1997.
The 8 1/2% Notes are redeemable in whole or in part at the option of the Company, at any time on or after February 15, 2002, at the redemption prices set forth below plus, in each case, accrued and unpaid interest, if any, thereon.
Prior to February 15, 2002, the Company may redeem the 8 1/2% Notes, in whole or in part, at the Make-Whole Price, plus accrued and unpaid interest, if any, through the date of redemption. The Make-Whole Price is defined as the greater of (i) the sum of outstanding principal amount and Make-Whole Amount (defined below) of such 8 1/2% Notes, and (ii) the redemption price of such 8 1/2% Notes on February 15, 2002, determined pursuant to the 8 1/2% Notes Indenture (104.25% of the principal amount). The Make-Whole Amount is defined as the excess, if any, of (i) the present value of the remaining interest premium and principal payments due on such 8 1/2% Notes as if such 8 1/2% Notes were redeemed on February 15, 2002, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (ii) the outstanding principal amount of such 8 1/2% Notes. In addition, during the first 36 months after February 11, 1997, the Company may redeem up to $70 million in aggregate principal amount of the 8 1/2% Notes at a redemption price of 108.5% of the principal amount thereof plus accrued and unpaid interest, if any, thereon to the redemption date with the net proceeds of an offering of common equity of the Company; provided that at least $130.0 million in aggregate principal amount of the 8 1/2% Notes remain outstanding immediately after the occurrence of such redemption. Any such redemption must occur within 60 days of the date of the closing of such common equity offering.
Upon a "change of control" in the Company, as defined in the 8 1/2% Notes Indenture, the 8 1/2% Notes holders may require, at their election, that the Company prepay all or a portion of the 8 1/2% Notes at a purchase price equal to 101% of the aggregate principal amount thereof plus accrued and unpaid interest, if any, thereon. Furthermore, under certain circumstances, the Company may become obligated to offer to purchase all or a portion of the 8 1/2% Notes at 100% of the principal amount thereof, together with accrued and unpaid interest, if any, with the net proceeds of certain asset sales.
The 9 1/2% Notes Indenture and the 8 1/2% Notes Indenture both contain certain covenants which include the following: (i) limitations on disposition of proceeds from asset sales; (ii) limitations on payment of dividends, making of distributions or certain investments; (iii) limitations on the incurrence of additional indebtedness or liens (iv) limitations on sale and leaseback transactions; (v) limitations on mergers, consolidations and transfers of substantially all of the Company's assets; and (vi) limitation on certain transactions with affiliates.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The 9 1/2% Notes and the 8 1/2% Notes are both subordinate to the Senior Credit Facility and rank pari passu with each other.
7% EXCHANGEABLE SUBORDINATED NOTES
On November 6, 1996, in conjunction with a public offering of common stock by the Company, the Company's Exchangeable Notes were exchanged into a total of 2,343,047 shares of common stock. The exchange resulted in a non-cash credit to stockholder's equity totaling $35.8 million, representing principal, accrued deferred interest and capitalized debt issuance cost relating to the Exchangeable Notes.
At the current stage in the bankruptcy proceedings, it is not possible to project the Company's aggregate long-term debt maturities for the next five calendar years, however, the scheduled maturities would be as follows:
The fair values of the Company's fixed rate 9 1/2% Notes and 8 1/2% Notes at December 31, 1998 were $128.8 million and $146.4 million, respectively based on current market prices at December 31, 1998.
NOTE 5 -- INCOME TAXES
The Company's (provision) benefit for income taxes is as follows:
The Company's deferred income tax assets and liabilities were comprised of the following differences between financial and tax reporting (in thousands):
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
At December 31, 1998 and 1997, the Company had approximately $160 million and $39 million, respectively, of unrecognized deferred tax assets comprised mainly of capitalized costs and write-offs and net operating loss ("NOL") carryforwards available to offset future taxable income for federal purposes. Valuation allowances have been provided against these deferred tax assets as it is presently more likely than not that the benefit will not be utilized. The Company continues to evaluate the realizability of its deferred tax assets and its estimate is subject to change. The Company had no deferred tax asset valuation allowance at December 31, 1996.
A reconciliation of the federal statutory income tax rates to the Company's effective rate is as follows:
At December 31, 1998, the Company had a NOL carryforward for tax purposes of $156.8 million. The NOLs will expire unless otherwise utilized, beginning in 1999. The utilization of NOL carryforwards is subject to limitations under U.S. Federal Income Tax Laws. The NOL carryforwards may be reduced or eliminated as a result of the bankruptcy (See Note 1).
NOTE 6 -- STOCK BASED COMPENSATION PLANS
The Company has adopted the disclosure provisions of SFAS No. 123. Accordingly, no compensation costs have been recorded for the stock options or warrants as the exercise price of all options granted was the fair market value on the date of grant.
The Company has reserved 6,100,000 shares of common stock for issuance to officers, employees, and directors under stock option and employee stock purchase plans.
STOCK OPTION PLANS
The exercise price for options granted to directors, officers and employees is the fair market value of the stock at the date of grant. The outstanding options have varying vesting periods, expire at various dates through the year 2008, and are exercisable at prices ranging from $5.56 to $34.75 per share, with an aggregate exercise price of $68.5 million.
The Company's President and Chief Executive Officer has the right to require the Company to purchase any shares of Common Stock owned as a result of the exercise of stock options at the then current market price of the Common Stock and any unexercised stock options at the excess of the fair market value of the Common Stock over the option price, upon (i) a termination of employment, (ii) the maturity of, or inability to obtain financing to exercise the stock options and (iii) any expiration of the right to exercise stock options.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following table summarizes the stock option activity for 1996, 1997 and 1998:
The following table summarizes information about stock options outstanding at December 31, 1998:
The weighted average fair value for options granted during 1998, 1997 and 1996 was $4.98, $13.30 and $12.95, respectively.
If compensation expense for the stock options and warrants had been determined and recorded based on the fair value on the grant date and using the Black-Scholes option pricing model to estimate the theoretical future value of those options, the Company's net income (loss) and net income (loss) per share amounts would have been reduced to the pro forma amounts indicated below:
Due to the uncertainties in these estimates, such as market prices, exercise possibilities, and the possibility of future awards and cancellations, these pro forma disclosures are not likely to be representative of the effects on reported income for future years.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
For proforma purposes, the fair value of each option grant is estimated on the date of grant with the following weighted-average assumptions:
On February 1, 1999, all options then outstanding were cancelled and reissued with an exercise price of $1.275 per share, the current fair market of the underlying stock plus 20%. As a result of this repricing of options, the plan changed from a fixed option plan to a compensatory plan for accounting purposes. All other terms of options previously granted to non-executives remained unchanged. The number of options held by executives and directors was reduced by approximately 114,000 shares.
STOCK PRICE PERFORMANCE INCENTIVE PLAN
On November 21, 1996, the Board of Directors of the Company adopted the 1997 Stock Price Performance Incentive Plan (the "Performance Plan") covering all employees of the Company which was approved by shareholder vote in May 1997. The Performance Plan has a commencement date of January 1, 1997 and expires on December 31, 1999. The purpose of the Performance Plan is to provide a meaningful financial incentive to employees that will assist the Company in recruiting and retaining high quality industry professionals, while simultaneously benefiting the shareholders by aligning the financial interests of employees with those of the shareholders by focusing their efforts on the price performance of the stock. The plan provides that should the price of the Company's stock reach $60 per share at any time during the term of the plan, every employee will receive a non-cash award of the right to receive common stock in the Company in an amount equivalent in value to five (5) times his/her annual salary on January 1, 1997 (or date of hire, if later). For employees hired after January 1, 1997, the award will be prorated giving consideration to the date of hire and the stock price on the date of hire. The right to receive the common stock, and the granting of the common stock, will vest to each employee still employed by the Company, in equal amounts, on the first through third anniversaries of the date that the common stock reaches $60 per share.
Should the price of the common stock not reach $60 per share during the term of the plan, but reaches $50 per share, each employee will receive, on December 31, 1999, a similar right to receive common stock with similar vesting provisions but with an equivalent value of two and one-half times his/her salary. That right would vest, in equal amounts on December 31, in the years 2000 through 2002. Compensation expense will be recognized by the Company from the award date through the vesting period with a cumulative recognition of compensation expense recognized on the date of award, giving consideration to employee services rendered prior to the award date. For the year ended December 31, 1998, annual salaries for all employees were approximately $21 million.
STOCKHOLDER RIGHTS PLAN
On December 10, 1997 the Company adopted a stockholder rights plan (the "Rights Plan"). Under the Rights Plan, as amended during 1998, each shareholder became entitled to receive one right for each outstanding share of common stock, should a triggering event occur. The rights which expire on December 10, 2007 become exercisable if a person or group acquires 15% or more of the Company's outstanding voting stock or announces a tender or exchanger offer that would result in ownership of 15% or more of the outstanding voting common stock.
Each right will entitle the holder to buy one one-thousandth of a share of a new series of junior participating preferred stock at an exercise price of $200 per right, subject to antidilution adjustments. Each one one-thousandth of a share of this new preferred stock has the dividend and voting rights of, and is designed to be substantially equivalent to, one share of common stock. Forcenergy's Board of Directors may, at its option, redeem all rights for $.01 per right at any time prior to the acquisition of 15% or more of Forcenergy's voting stock by a person or group.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
If a person or group acquires 15% or more of Forcenergy's outstanding voting stock, each right will entitle holders, other than the acquiring party, to purchase for $200 shares of Forcenergy common stock having a market value of twice that amount.
The plan also includes an exchange option. If a person or group acquires 15% or more, but less than 50%, of the outstanding voting stock, the Board of Directors may, at its option, exchange the rights in whole or in part for shares of Forcenergy stock. Under this option, Forcenergy would issue one share of common stock, or one one-thousandth of a share of the new preferred stock, for each outstanding right. This exchange would not apply to shares held by the person or group holding 15% or more of Forcenergy's voting stock.
If, after the rights have become exercisable, Forcenergy merges or otherwise combines with another entity, or sells 50% or more of its assets or earning power, each right then outstanding will entitle its holder to purchase for $200, subject to antidilution adjustments, a number of the acquiring party's common shares having a market value of twice that amount.
EMPLOYEE STOCK PURCHASE PLAN
The Company has adopted the Forcenergy Employee Stock Purchase Plan (the "Stock Purchase Plan"), which permits full-time Company employees (or part time for at least 20 hours per week and at least five months per year) to acquire common stock at a small discount from its fair market value through payroll deductions. Up to a maximum 100,000 shares of common stock may be sold to participants under the Stock Purchase Plan. As of December 31, 1998, a total of 95,281 shares had been purchased by participants in the plan. As a result of the bankruptcy, all monies deducted from payroll and not yet used to purchase common stock were returned to participants.
NOTE 7 -- EARNINGS PER SHARE
The following reconciles the numerators and denominators of the basic and diluted EPS computations (in thousands, except per share data):
(1) The effect of 415,348 and 1,293,866 shares of potential common stock were anti-dilutive in 1998 and 1997, respectively, due to the losses in both years.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 8 -- FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK
During 1998, 1997 and 1996, the Company was a party to various financial instruments with off-balance-sheet risk in the normal course of business to reduce its exposure to changing commodity prices. The Company utilizes these arrangements for portions of its current oil and gas production to achieve more predictable cash flows and to reduce its exposure to fluctuations in oil and gas prices. The remaining portion of current production is not hedged so as to provide the Company the opportunity to benefit from increases in prices on that portion of the production, should price increases materialize. The Company had various instruments in place, all of which were cancelled at the option of the counterparties subsequent to the filing of Chapter 11 under the U.S. Bankruptcy Code (see Note 1). The Company received $5.5 million (fair market value) in settlement of the contracts pursuant to the cancellations. The Company may enter into new arrangements in the future as part of its strategy to reduce exposure to commodity price fluctuations. The instruments are utilized to hedge oil and gas prices for varying time periods. The instruments contain an element of credit risk and price risk. The Company attempts to minimize the extent of credit risk by limiting the counterparties to major banks or significant industry participants. All of these arrangements are entered into on a no-cash basis and are settled monthly. The Company accounts for these arrangements as hedging activities and, accordingly, gains or losses are included in oil and gas revenues for the period the production was hedged. Since 1994, the Company has entered into a number of arrangements with oil and gas purchasers and industry trading companies. Under these agreements, monthly settlements are based on the differences between the prices specified in the instrument and/or the settlement price of certain oil and gas futures contracts quoted on the New York Mercantile Exchange ("NYMEX"). In instances where the applicable settlement price is less than the price specified in the contract, the Company receives a settlement based on the difference and in instances where the applicable settlement price is higher than the specified prices, the Company pays an amount based on the difference. As a result of these hedging activities, the Company recognized additional oil and gas sales revenue of $15.8 million in 1998 and a reduction to field revenue of $10.8 million and $20.5 million in 1997 and 1996, respectively.
NOTE 9 -- LEASES
The following is a schedule, by calendar year, of future minimum rental payments, covering primarily office space, required under operating leases with a term in excess of one year:
Total rental expense for operating leases was approximately $1,976,000, $1,765,000 and $584,000 for the years ended December 31, 1998, 1997 and 1996, respectively.
NOTE 10 -- COMMITMENTS AND CONTINGENCIES
The Company is involved in various litigation matters arising in the normal course of business. Management's assessment is that none of these matters are anticipated to have a material adverse affect on the financial position or results of operations of the Company.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 11 -- SIGNIFICANT CUSTOMERS
The following table reflects sales to oil and gas purchasers who individually accounted for more than 10% of the Company's total oil and gas revenues in a given year (in thousands):
During 1998, two purchasers of the Company's production accounted for more than 10% of the value of oil and gas sold by the Company. Based on current demand for oil and natural gas sold, the Company does not believe the loss of these purchasers would have a material adverse effect on the Company's results of operations or cash flow. The Company currently relies on one purchaser for its Alaska production. The contract with this purchaser runs through December 1999 at which time a new contract must be negotiated or another purchaser found. The inability to negotiate a new contract or to find a new purchaser could materially impact the company's results of operations and cash flows.
NOTE 12 -- CURRENT ASSETS AND LIABILITIES
Current assets and liabilities include the following:
(1) As of December 31, 1998, these items are subject to compromise.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 13 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
During October 1997 Forcenergy acquired Edisto Resources Corporation and Convest Energy Corporation for Forcenergy common stock and cash balances Forcenergy received in the mergers. The accompanying financial statements include the following attributable to the Edisto and Convest mergers:
On March 31, 1998 the Company issued approximately 7.9 million shares of common stock valued at $27 per share pursuant to the tender offer for all of the outstanding common stock of FAB (see Note 2).
The Company paid cash interest costs, including capitalized interest, of $49.0 million, $34.8 million, and $11.5 million for the years ended December 31, 1998, 1997 and 1996, respectively.
NOTE 14 -- SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED) (IN THOUSANDS EXCEPT PER SHARE DATA)
(1) Includes $275 million and $200 million ($162.8 million after tax) non-cash impairments of oil and gas assets recorded in the fourth quarters of 1998 and 1997, respectively, pursuant to the full cost accounting rules mandated by the Securities and Exchange Commission ("SEC").
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 15 -- SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
COST INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
Presented below are costs incurred in petroleum property acquisition, exploration and development activities (in thousands):
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
The following table presents total capitalized costs of proved and unevaluated properties and accumulated depletion, depreciation and amortization related to oil and gas producing operations (thousands):
Of the capitalized costs of unevaluated properties at December 31, 1998, approximately $76,313,000, $32,182,000, $28,518,000 and $28,872,000 were incurred in 1998, 1997, 1996 and years prior to 1996, respectively. The Company anticipates evaluating these properties over the next three to five years as it continues its property exploitation and development program.
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities, which do not include revenues associated with the production and sale of sulfur and processing fees for third party gas, and excluding corporate overhead and interest costs are as follows (in thousands):
- ---------------- (1) Does not include 1998 hedging gain of $15.8 million and 1997 and 1996 hedging losses amounting to $10.8 million and $20.5 million, respectively. (2) Net of effects of hedging. (3) Includes condensate, crude oil and natural gas liquids.
FORCENERGY INC FORCENERGY INCFORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
RESERVE QUANTITIES (UNAUDITED)
Estimates of proved reserves of the Company and the related standardized measure of discounted future net cash flow information are based on the reports of independent petroleum engineers. All of the Company's proved reserves are located offshore or onshore - United States. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. The reserve data set forth herein represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material.
The present value of estimated future net cash flows included herein should not be construed as the current market value of estimated oil and natural gas reserves attributable to the Company's operations. In accordance with the applicable requirements of the Commission, the estimated discounted net cash flows from proved reserves are generally based on current prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Current prices in effect as of the valuation date incorporated the estimated effects of hedging agreements in place (see Note 8) as of the valuation date, and for the period the agreements will be in effect. Actual future cash flows will also be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by purchasers and changes in governmental regulation or taxation. The timing of actual future net cash flows from proved reserves, and their actual present value, will be affected by the timing of both production and the incurrence of expenses in connection with development and production of oil and gas properties. In addition, the calculation of the present value of the future net revenues using a 10% discount as required by the Commission, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and the risk associated with the Company's reserves or the oil and gas industry in general. The Company's estimates of its proved reserves and proved developed reserves of oil and gas as of December 31, 1996, 1997 and 1998 and the changes in its proved reserves are as follows:
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(1) Includes crude oil, condensate and natural gas liquids.
Proved reserves are estimated quantities of liquids and natural gas which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
Revisions to previous estimates for the year ended December 31, 1998 were primarily the result of lower prices the effect of those prices on the economic life of the properties. In 1997, an 11 million barrel price-related negative volume reduction in the Alaskan reserves, due to a technical reduction in the economic life of the reserves, was substantially offset by other upward revisions. Upward revisions to previous estimates in 1996 primarily resulted from property performance.
FORCENERGY INC (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows (in thousands):
The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows (in thousands):
The standardized measure is based on current prices as of the valuation date and reflects overall weighted average prices of:
The standardized measure of discounted future net cash flows was calculated by applying current prices to estimated future production, less future expenditures (based on current costs) to be incurred in developing and producing such proved reserves and the estimated effect of future income taxes based on the current tax law. The resulting future net cash flows were discounted using a rate of 10% per annum.
During the first half of 1999, oil and gas prices have increased from those being received as of the year-end reserve valuation date. If prices decline from year-end levels, if not offset by other factors, the value of the Company's reserves could be negatively impacted.