10-K/A 1 g64243e10-ka.txt FORCENERGY INC AMENDMENT TO 10-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ FORM 10-K/A (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ____________ TO____________

COMMISSION FILE NUMBER: 0-26444 FORCENERGY INC. (Exact Name of Registrant as Specified in Its Charter) DELAWARE 65-0429338 (State or other jurisdiction of incorporation or (I.R.S. Employer Identification No.) organization) 2730 S.W. 3RD AVENUE SUITE 800 MIAMI, FLORIDA 33129-2356 (Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (305) 856-8500 Securities Registered Pursuant to Section 12(b) of the Act: NONE Securities Registered Pursuant to Section 12(g) of the Act: COMMON STOCK, PAR VALUE $.01 PER SHARE Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by checkmark if disclosure of delinquent filings pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PRECEDING FIVE YEARS: Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes [X] No [ ] On February 15, 2000, the Registrant's Chapter 11 plan became effective, old shares of common stock were cancelled and new shares of common stock were authorized and issued. As of March 28, 2000, the total number of outstanding shares of new Common Stock is 24,000,000. The aggregate market value of the voting and non-voting equity held by non-affiliates was estimated to be $113 million at March 29, 2000. DOCUMENTS INCORPORATED BY REFERENCE: Proxy statement of Forcenergy Inc relative to the Annual Meeting of Shareholders on June 7, 2000 which is incorporated by reference into Part III of this Form 10-K. 2 FORM 10-K/A FORCENERGY INC TABLE OF CONTENTS

i 3 DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical fact included in this Form 10-K, including without limitation, statements under "Business" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" regarding prediction of future events, assessments of materiality, the effects of pending litigation, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled in 2000 and thereafter, Forcenergy's financial position, compliance with financial covenants in loan agreements, business strategy and other plans and objectives for future operations, are forward-looking statements. In addition, when used in this Annual Report on Form 10-K, the words "anticipates," "believes," "estimates," "expects," "intends," "plans" and similar expressions are intended to identify forward-looking statements. Although Forcenergy believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of Forcenergy. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates and such revisions, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. All subsequent written and oral forward-looking statements attributable to Forcenergy or persons acting on its behalf are expressly qualified in their entirety by such factors. Readers are cautioned not to place undue reliance on any forward-looking statements contained in this Annual Report on Form 10-K, which speak only as of the date of this Annual Report. Forcenergy undertakes no obligation to release publicly the result of any revisions to these forward-looking statements that may be made to reflect events or circumstances after the filing date of this Annual Report or to reflect the occurrence of unanticipated events. 4 PART I ITEM 1. BUSINESS OVERVIEW Forcenergy Inc, a Delaware corporation (the "Company" or "Forcenergy"), 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 nine 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. At December 31, 1999, Forcenergy had net estimated proved reserves of approximately 115.0 MMBOE, 52% of which were located in the Gulf of Mexico and 24% of which were located in Alaska. Approximately 56% of the Company's net estimated proved reserves on such date were oil and approximately 71% of these proved reserves were classified as proved developed. The Company currently operates approximately 70% of its Gulf of Mexico production. The Company's primary focus is currently its Gulf of Mexico and Alaska activities. The Company has also acquired interests in certain undeveloped international leasehold acreage in Gabon, Africa and Australia. REORGANIZATION On March 21, 1999 (the "Petition Date"), the Company and its wholly-owned subsidiary, Forcenergy Resources Inc., filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code. The filings were made in the United States Bankruptcy Court for the Eastern District of Louisiana in New Orleans, Louisiana (the "Bankruptcy Court"). The Company and Forcenergy Resources Inc. operated their businesses as debtors-in-possession subject to the jurisdiction of the Bankruptcy Court from the Petition Date to February 15, 2000. The Company's Plan of Reorganization was confirmed (approved) by the Bankruptcy Court on January 19, 2000. The Plan of Reorganization was declared effective on February 15, 2000 (the "Emergence Date"). Notes 1 and 2 to the Company's Consolidated Financial Statements, included elsewhere in this Form 10-K, provide information regarding the Company's Chapter 11 proceedings and the adoption of fresh start reporting at December 31, 1999, to give effect to the emergence as though it had occurred on that date. STRATEGY The Company's overall business 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 area. During 1999, as a result of the bankruptcy proceedings and the related restrictions on the use of cash, Forcenergy focused on minimizing production declines on existing producing properties, through workovers and the drilling of lower risk exploitation wells, and on performing detailed reviews of both producing fields and its prospect inventory for purposes of adding to its present list of drillable projects. Gulf of Mexico. The Company's business strategy in the Gulf of Mexico 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 substantial 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 1 5 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 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 with existing infrastructure results in the addition of new production with minimal incremental lease operating expenses and minimal additional facility costs. Also avoided are lengthy 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, 1999, Forcenergy operated 119 structures and 440 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. These companies have reduced their activity in the region over the past ten to twenty years as they have refocused their Alaskan efforts on the North Slope (Prudhoe Bay) area. 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 to expand 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 seventh largest exploratory lease position in the State of Alaska, both of which will give Forcenergy an opportunity to add significant new reserves through drilling. In 1998, Forcenergy completed the largest proprietary 3-D seismic survey in Cook Inlet and since then has acquired additional 3-D seismic data to identify additional drilling prospects. Forcenergy believes that its strategy 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. The Company intends to pursue an active development and exploration program in the Cook Inlet for at least the next two or three years. International. Forcenergy's international business strategy has historically been aimed at achieving significant reserve growth through participation in selected high risk, high reward exploration prospects. Going forward the Company will lower its risk by farming out exploratory projects to industry partners while still maintaining a meaningful working interest position. 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 Australia. 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 848 square miles of 3-D seismic surveys on 105 of its 175 offshore Gulf of Mexico lease blocks and 2,305 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 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 will enable the Company to identify multiple development and exploratory prospects in mature producing fields, which were not identified 2 6 through earlier technologies. Forcenergy's professional staff includes 16 geoscientists experienced in interpreting 3-D data. 1999 AND 1998 DRILLING ACTIVITY During the bankruptcy process in 1999, Forcenergy's capital program was restricted by the Bankruptcy Court. Available capital was used primarily to minimize production declines and maximize cash flow by targeting development and lower-risk exploitation prospects. During 1999, Forcenergy spent $69.7 million on its capital drilling and workover program, including $7.5 million in capitalized internal costs and $6.1 million on undeveloped leasehold and seismic costs. Gulf of Mexico. The Company spent approximately $46.2 million for capital drilling expenditures in the Gulf of Mexico during 1999. Three of three development wells and four of six exploratory wells drilled proved successful. The most significant activity centered around the exploitation and development of producing properties. Two exploratory wells and one development well were successfully drilled at the Vermilion 380 field (100% working interest). These wells commenced production in October 1999 at an average rate of 1,200 barrels of oil equivalent per day and added an estimated 1,534 MBOE to the proved reserve base during 1999. Forcenergy spent approximately $150.2 million for capital drilling expenditures in the Gulf of Mexico during 1998 adding approximately 19,725 barrels equivalent of production per day and added approximately 9.6 million barrels equivalent to the proved reserve base in 1998. Three of four development wells and thirteen of twenty exploratory wells drilled proved successful. 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 successfully 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. Cook Inlet, Alaska. The Company's major priority in Alaska in 1999 was to resume the construction of the Osprey Platform for the Redoubt Shoal prospect. The Company anticipates that the platform will be set by the third quarter of 2000 and drilling will commence during the fourth quarter. During 1998, 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. Also 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 $6.1 million in total capital was spent on onshore properties during 1999. The majority of these expenditures were spent on recompletions and workovers of wells in existing producing fields. Approximately $39.4 million in total capital was spent during 1998, $10.7 million of which was incurred on unproved leases primarily in east Texas, and $9.1 million for the acquisition of producing properties in southeastern New Mexico and 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. Forcenergy has acquired a large-scale proprietary 3-D seismic survey over the southern portion of the offshore Gryphon Marin 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. The Company is currently reviewing various farmout opportunities for both concessions. In Australia, the Company drilled or reentered 11 wells during 1998 and early 1999 on its 2.4 million acre PEL 238 concession in New South Wales, a coal bed methane gas prospect. Dewatering of these wells continues, however, they have not produced at commercial rates. Forcenergy plans to drill at least 3 additional 3 7 wells on the PEL 238 concession to further evaluate a conventional gas play and to fulfill the remaining earning requirements of the concession. ADDITIONAL FUTURE PROJECTS Forcenergy's reduced drilling activity during the bankruptcy process allowed it to focus the attention of its technical personnel on data previously acquired for the purpose of generating additional new prospects on its existing properties. As a result of that effort, 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. Many of these projects are currently being reviewed by Forcenergy's geoscientists utilizing 3-D seismic data acquired in the last three years. The Company's budget for fiscal 2000 provides for $142 million in capital expenditures including $13.5 million in capitalized internal costs. The Company expects to spend approximately $79 million, $48 million and $13 million in the Gulf of Mexico, Alaska and Onshore, respectively, and approximately $2.0 million internationally. GULF OF MEXICO PROPERTIES Forcenergy currently holds working interests in 210 federal offshore and state lease blocks located in the Gulf of Mexico and Gulf Coast, including a 100% working interest in 60 of these blocks and a 50% or greater working interest in 26 other blocks, and operates 58 of the producing blocks representing 70% 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 79% of Forcenergy's net proved reserves in the Gulf of Mexico and 41% of Forcenergy's total net proved reserves, as of December 31, 1999:

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, both non-operated properties purchased from Marathon Oil Company in 1996. Forcenergy also owns a 100% working interest in 4 8 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 28.1 million barrels of oil and comprised approximately 24% of Forcenergy's total estimated net proved reserves at December 31, 1999. Through lease sales, the Marathon and Stewart acquisitions and several other smaller property acquisitions, Forcenergy has assembled the seventh largest exploratory lease acreage position in the State of Alaska. ONSHORE PROPERTIES Forcenergy owns working and royalty interests in approximately 1,990 producing oil and gas wells in 882 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 24% of estimated net proved reserves at December 31, 1999. 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. Approximately 95% of the Company's proven oil and natural gas reserves are mortgaged to secure borrowings under the Company's current senior credit facility (see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources"). 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 using period end prices and costs, 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. Under the full cost accounting rules the Company's reserves exceeded the recorded cost at December 31, 1999. However, based on prices being received as of December 31, 1998 and 1997, the Company recorded non-cash impairments in the fourth quarters ended December 31, 1998 and 1997 of $275 million and $200 million ($162.8 million after tax), respectively, pursuant to full cost accounting rules. Although oil and gas prices are currently higher than those at year end 5 9 1999, if prices decreased significantly, the Company's capitalized costs could again exceed the present values of estimated future net revenue. If these capital costs were not offset by other factors, they could result in additional writedowns of Forcenergy's 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. The Company also accounts for these future liabilities by including all projected abandonment costs as a reduction in the future cash flows from its reserves in its reserve reporting. As of December 31, 1999, total undiscounted abandonment costs estimated to be incurred were approximately $144.8 million 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 $6.4 million in abandonment costs are anticipated to be incurred in 2000, all of which will be funded by cash flow from operations or from temporary borrowings. The Minerals Management Service ("MMS") requires operators 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 MMS may also require that operators provide supplemental bonding on a property-by-property basis to insure that funds will be available to properly plug and abandon the wells and facilities once the fields are depleted. The Company currently provides approximately $80 million in supplemental bonding on its operated 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 6 10 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, several purchasers of the Company's production individually accounted for more than 10% of the value of oil and gas sold by the Company as follows:

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 2000 at which time that contract must be extended or renegotiated or another purchaser found. The net price provided for under this contract is at a slight discount to the West Texas Intermediate price as quoted on the New York Mercantile Exchange ("NYMEX"), 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 13 to the Company's Financial Statements). The Company utilizes, 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 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. See Note 10 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. 7 11 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 current owner and operator of the site or sites where the release occurred, the owner and operator at the time 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 liabilities 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. Although the Company is not aware of any circumstances which would give rise to CERCLA liability, it has not eliminated the possibility that past releases have occurred on property now owned and operated by the Company. The discovery of such past releases could cause the Company to incur material costs under CERCLA. 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 party 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 adjustment annually based on changes in the Consumer Price Index) 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. 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 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, OPA places a burden on offshore lease holders to conduct safe operations and take other measures to prevent oil spills; if one occurs, 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 conditions or 8 12 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, 1999, there is no assurance that material costs relating to environmental matters will not be incurred in the future. GOVERNMENT REGULATION Forcenergy's drilling, production, 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 recently issued two final rules amending its regulations governing the valuation, for royalty purposes, of natural gas produced from Indian leases and oil produced from federal lands. With regard to the amended regulations concerning Indian leases, which became effective January 1, 2000, the MMS added alternative valuation methods to ensure that Indian lessors receive maximum revenues from their mineral resources. In the second final rule, which becomes effective June 1, 2000, the MMS is amending the regulations governing the valuation of crude oil produced from Federal leases. The amendments addressing federal leases include, inter alia: (1) changes to the valuation of oil that is not sold pursuant to an arm's-length contract; (2) optional methods for valuing crude oil production where it is sold at arm's-length following one or more arm's-length exchanges or one or more transfers between affiliates; (3) changes to the method of calculating actual transportation costs; (4) changes to the definition of "affiliate" due to recent judicial opinions; (5) clarification that the MMS will issue binding value determinations; and (6) additional regulatory language clarifying that the MMS will not "second-guess" the value of the oil subject to a sale under an arm's-length contract, unless the MMS finds that a seller acted unreasonably or in bad-faith in the sale of oil from a lease. Additionally, the MMS is currently conducting a rulemaking concerning the valuation, for royalty purposes, of oil produced from Indian lands. The Company does not expect to experience any adverse material effect as a result of the changes implemented by the final rules or the changes that could result from the ongoing rulemaking, although the full impact of the amendments to the MMS' valuation methodology on the Company's performance cannot be determined at this time. The interstate transportation and sale for resale of natural gas are regulated by the Federal Energy Regulatory Commission ("FERC"). Commencing in 1985 and continuing with the issuance of Order No. 636 in 1992, the FERC promulgated a series of orders and regulations that significantly fostered competition in the business of transporting and marketing natural gas. These orders and regulations induced, and ultimately required, interstate pipeline companies to provide nondiscriminatory transportation services to producers, marketers, and other shippers, regardless of whether those shippers were affiliated with an interstate pipeline company. The FERC's initiatives have led to the development of a competitive, unregulated, open access 9 13 market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than the pipelines. On February 9, 2000, the FERC issued Order No. 637, which permits, and in some cases, requires, interstate natural gas pipelines to make certain changes to the nature of interstate transportation services. The changes permitted or required by Order No. 637 attempt to continue the development of competitive natural gas markets under the open access regime created by Order No. 636. These changes include, inter alia: (1) elimination, for a two-year period, of the rate cap that applies to sales of released firm transportation capacity by pipelines' firm shippers; (2) the adoption by pipelines of seasonal or term-differentiated rates; (3) revisions to pipeline scheduling procedures that are designed to place capacity released by firm shippers on a more equal footing with capacity sales by pipelines; and (4) additional reporting requirements that seek to increase the ability of the FERC and interested parties to monitor the actions of pipelines and firm capacity holders and detect attempts to exercise market power or to engage in unduly discriminatory conduct. The Company does not expect to experience any adverse material effect as a result of these changes, although the full impact of Order No. 637 on the Company's performance cannot be determined at this time. The FERC also has the authority, under the Interstate Commerce Act ("ICA"), to regulate the rates and service conditions for the interstate transportation of crude oil, liquids and condensate by common carrier pipelines. The ICA requires that the rates charged by interstate common carriers, such as Cook Inlet Pipeline Company, be just and reasonable and nondiscriminatory. On January 1, 1995, the FERC adopted regulations that established an indexing system for petroleum pipeline transportation rates that permits petroleum pipelines to change their rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods. Rate increases made pursuant to the index are subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. 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 in excess of those that would have been collected under a just and reasonable and nondiscriminatory rate. 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 the complaint. In addition, Cook Inlet Pipeline Company is subject to regulation by the Alaska Public Utilities Commission with respect to any intrastate transportation provided by Cook Inlet Pipeline Company. In addition, all pipeline operations on or across the outer continental shelf are regulated under the OCSLA. Under the FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis, while gathering services are treated as non-jurisdictional activities not subject to the FERC's jurisdiction. In 1996, the FERC issued a Statement of Policy regarding its jurisdiction under the Natural Gas Act ("NGA") and OCSLA over new natural gas facilities and services on the OCS. Generally, the FERC retained its existing tests for determining the jurisdictional status of offshore facilities, but eased the application of its jurisdiction over facilities in water depths of 100-meters or more. Legislation and regulations affecting the oil and gas industry are 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. 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. 10 14 EMPLOYEES As of February 28, 2000, Forcenergy had 258 full time employees, 22 of whom are located at the Company's corporate headquarters in Miami, Florida and 87 of whom are located at the Company's operational headquarters in Metairie, Louisiana and in its regional offices in Lafayette and Intracoastal City, Louisiana, and Anchorage, Alaska. One hundred and thirty seven employees work offshore in the Gulf of Mexico and 12 work in other field locations. None of Forcenergy's employees are represented by a labor union and the Company does not anticipate difficulty in labor relations. 11 15 PART II 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, 1999 and should be read in conjunction with the financial statements of the Company appearing elsewhere in this report. For the period from March 21, 1999 to February 15, 2000 the Company operated as a debtor-in-possession. Effective December 31, 1999 the Company adopted fresh start reporting; accordingly the following results of operations express those of the predecessor company. 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 and excluding the $5.5 million settlement on the cancellation of hedging contracts by the counterparties subsequent to the Company's filing of Chapter 11. (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, 1999 and December 31, 1998 Net Income/Loss. The Company reported income, before reorganization items, income taxes and extraordinary items, of $19.8 million for 1999 compared to a loss in 1998 of $39.5 million, exclusive of a non-cash impairment of oil and gas assets. During 1999, the Company recorded reorganization costs/charges of $69.9 million and recorded an extraordinary gain on discharge of indebtedness of $160.0 million pursuant to the bankruptcy plan of reorganization. During 1998 the Company recognized a $275.0 million non-cash impairment of oil and gas assets pursuant to full cost accounting rules mandated by the Securities and Exchange Commission. The special items are discussed in more detail below. Including the special items for both years, the Company reported net income of $109.9 million for 1999 compared to a net loss of $314.5 million in the prior year. The increase in net income is mainly due to an increase in operating income, the non-cash impairment recorded in 1998 and the extraordinary item recorded in 1999, partially offset by the reorganization costs incurred during 1999 (all discussed below). 12 16 Operating Income/Loss. For the year ended December 31, 1999, operating income rose to $45.1 million compared to a $268.0 million operating loss recorded for 1998. The increase in operating income is mainly due to a decrease in lease operating expenses in 1999, lower depletion, depreciation and amortization expense associated with lower production volumes in 1999 and the fact that 1998 included a $275.0 million non-cash impairment recorded in the fourth quarter of 1998 pursuant to full cost accounting rules mandated by the Securities and Exchange Commission. Production. The Company's net liquids production was 7,877 MBbls in 1999 compared to 8,513 MBbls in 1998. Net gas production was 61,048 MMcf for the year ended December 31, 1999 compared to 76,799 MMcf produced in 1998. Production of both liquids and gas production declined as the Company significantly reduced its capital expenditure program beginning in the third quarter of 1998 because of a lack of available capital, thereby limiting the Company's ability to maintain production rates and to replace reserves produced. The reduction in capital spending continued throughout 1999 while the Company operated under bankruptcy court orders. Revenues. Revenues were $266.7 million for the year ended December 31, 1999, compared to $273.5 million reported last year, as higher net realized prices only partially offset lower production volumes. Average net realized liquid prices rose to $15.48 per Bbl in 1999, a 24% increase compared with $12.54 per Bbl received in 1998. Average net realized gas prices increased to $2.27 per Mcf in 1999, a 5% increase compared with $2.16 per Mcf reported in the prior year. Average prices received for field production for 1999 were $16.12 per Bbl and $2.14 per Mcf for liquids and natural gas, respectively. After taking into account the effects of 1999 hedging activities entered into in order to guarantee a certain level of cash flow from production (excluding the $5.5 million settlement on the cancellation of hedging contracts by the counterparties subsequent to the Company's filing of Chapter 11), specifically a $5.0 million decrease in liquids revenue and a $7.7 million increase in gas revenue, net realized liquids prices were reduced to $15.48 per Bbl and natural gas prices increased to $2.27 per Mcf. Average field prices 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, specifically an $8.0 million increase in liquids revenue and a $7.7 million increase in gas revenue, net realized prices rose to $12.54 per Bbl and $2.16 per Mcf for liquids and natural gas, respectively. Lease Operating Expenses. Lease operating expenses were $87.0 million in 1999 compared to $99.2 million in 1998. The decrease related primarily to a reduction in the Company's workover program because of capital constraints during the bankruptcy process. On an equivalent unit of production basis, lease operating expenses increased to $4.82 per BOE in 1999 from $4.66 per BOE in 1998, because of the decline in production volumes. Depletion, Depreciation and Amortization ("DD&A"). DD&A expense declined to $116.4 million in 1999 from $145.9 million for 1998. The decrease was principally attributable to lower production volumes and a decrease in the DD&A rate per unit of production from $6.84 per BOE in 1998 to $6.45 per BOE in 1999. In addition, the Company recorded a non-cash impairment of oil and gas assets in the fourth quarter of 1998 of $275 million. General and Administrative Expense. General and administrative expenses, net of overhead reimbursements and capitalized internal costs, were $13.7 million in 1999 compared with $17.2 million in 1998. General and administrative expenses decreased primarily due to the closing of the Company's Houston office in late 1998 and a company-wide reduction in staffing in the first quarter of 1999. On a per BOE-produced basis, general and administrative expenses decreased to $.76 per BOE for 1999 compared with the $.81 per BOE reported for the 1998 year, despite the decrease in production volumes. Other Income. Interest and other income increased to $7.0 million in 1999 from $1.6 million in 1998. The increase was primarily attributable to the $5.5 gain recorded on the Company's sale of Forcenergy AB, an inactive Swedish subsidiary. Interest Expense. Interest expense, net of amounts capitalized, decreased to $32.3 million in 1999, compared to the $48.1 million incurred in 1998. The Company discontinued the accrual of interest on the 13 17 senior subordinated note issues after the Chapter 11 filing on March 21, 1999. This decrease in interest expense was partially offset by increased interest expense on higher average outstanding principal balances under the Old Senior Credit Facility in 1999 and the discontinuance of the capitalization of interest expense on unproved projects in June, 1999. Capitalization of interest expense on unproved properties was discontinued in connection with the cessation of development activities associated with these properties during the pendency of bankruptcy proceedings and because of the uncertainty as to whether, or when these properties would be developed. Reorganization Items. The Company recorded a net charge for reorganization items of $69.9 million during 1999 in connection with its reorganization under Chapter 11. Included in reorganization items for 1999 were legal and advisory fees amounting to $5.1 million, bank and other administrative fees amounting to $11.1 million and a charge of $56.0 million to restate the Company's assets to fair market value under the "fresh-start reporting rules" for companies emerging from bankruptcy (See Notes 1, 2 and 6 to the Consolidated Financial Statements included elsewhere in this Form 10-K), partially offset by interest income of $2.3 million associated with higher cash balances. Extraordinary Item. The Company recorded a $160.0 million extraordinary gain on the discharge of indebtedness in 1999 for the difference between the face value of the Company's 8 1/2% Senior Subordinated Notes and 9 1/2% Senior Subordinated Notes and unsecured trade accounts payable exchanged for new equity in the Company and the fair market value of that new equity under the Plan of Reorganization. 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 14 18 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. 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. LIQUIDITY AND CAPITAL RESOURCES The Company makes substantial capital expenditures for the exploration and development of oil and natural gas reserves in the ordinary course of business. 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 affect on the Company. Such a decline in prices or production could also adversely affect the amount that the Company could borrow under its credit facility. The availability of capital to the energy industry, in general, and from the public equity and debt markets, is also influenced by prevailing market sentiment that might be totally unrelated to the industry's current performance. On March 21, 1999, the Company and its wholly-owned subsidiary, Forcenergy Resources Inc., filed a voluntary petition for relief under Chapter 11 of Title 11 of the United States 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. Bankruptcy Court for the Eastern District of Louisiana in New Orleans. The Company continued to operate as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders until February 15, 2000, at which time the Plan of Reorganization (the "Plan" or "Reorganization") became effective (See Notes 1, 2 and 6 to the Consolidated Financial Statements included elsewhere in this Form 10-K). 15 19 In conjunction with the Reorganization, the Company replaced the prior senior credit facility (the "Prior Senior Credit Facility") with a new senior credit facility with essentially the same group of banks ("New Senior Credit Facility"). The New Senior Credit Facility consists of a $250 million Revolving Credit Facility (the "Revolver") and a $70 million Term Loan (the "Term Loan"). The amount that can be borrowed under the Revolver is further subject to a borrowing base, which has been established initially at $250 million through February 15, 2001. The Revolver provides for borrowings on a revolving basis through August 15, 2003, at which time all outstanding amounts under the Revolver become due and payable. Advances under the Revolver bear interest at prime plus 1.5% or LIBOR plus 2% per annum at the election of the Company. The agreement provides for a commitment fee on the unused portion of the Revolver at .50% due quarterly. The borrowing base is subject to semi-annual re-determination after the first re-determination on February 15, 2001. The terms of the Term Loan provide for mandatory quarterly principal repayments of $2.5 million commencing on March 31, 2001, with a $50 million balloon repayment at maturity on August 15, 2003. Interest is payable monthly on the Term Loan at prime plus 3% or at LIBOR plus 3.5%. On March 20, 2000 the Company collected $40.0 million in proceeds from the issuance of preferred stock and warrants as part of the Reorganization (See Note 2 to the Consolidated Financial statements included elsewhere in this Form 10-K). The proceeds were used to repay borrowings outstanding under the Revolver. At March 28, 2000 $164.1 million was drawn under the Revolver with $80.5 million available for use for general corporate purposes. 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:

Working capital at December 31, 1999 was $35.8 million, which included $96.5 million of cash, the majority of which has been used in the consummation of the Plan of Reorganization subsequent to year end. Accounts receivable balances were $41.3 million at December 31, 1999 compared to $28.4 million at December 31, 1998. The increase primarily relates to increased revenue receivables due to higher oil prices. Cash flow from operations before changes in working capital and reorganization items ("cash flow") was $137.6 million for the year ended December 31, 1999 compared with $107.4 in 1998. The increase in cash flow relates primarily to reduced lease operating expenses and interest expense cash proceeds from the sale of Forcenergy AB and settlement of hedging contracts (See Notes 4 & 10 to the Consolidated Financial Statements included elsewhere in this Form 10-K) offset by decreased revenues. Cash used in reorganization items during 1999 was $5.0 million. The Company will use approximately $11.2 million in cash to satisfy remaining unpaid reorganization costs accrued at December 31, 1999. Capital expenditures were $77.3 million during 1999 compared with $337.4 million in 1998. Capital expenditure activities decreased in 1999 while the Company operated for the majority of the year under bankruptcy court supervision. Capital expenditures for 1999 were funded primarily from the Prior Facility through the Petition Date and by cash flow from operations thereafter. The Company expects to spend approximately $142 million in 2000, including $13.5 million in capitalized internal costs, and exclusive of acquisitions, and expects to fund these expenditures with cash flow from operations. 16 20 The Company has historically entered into various financial instruments with off-balance sheet risk, to reduce its exposure to changing commodity prices. The Company normally 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 for varying time periods. 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 on the Petition Date, all of which were cancelled at the option of the counterparties subsequent to the Company's Chapter 11 bankruptcy filing. The Company received $5.5 million (fair market value of the contracts at the time) in cash in April 1999 in final settlement of the contracts. The settlements were included in oil and gas sales in the Consolidated Statements of Operations for the year ended December 31, 1999. The Company subsequently entered into several new financial hedging contracts ("Swaps") with respect to its future oil and natural gas production. 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. Swap contracts in place at December 31, 1999 (and including contracts entered into subsequent to year-end) on future oil production were as follows:

Swap contracts in place at December 31, 1999 (and including contracts entered into after year-end) on future natural gas production were as follows:

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-cost basis and are settled monthly. The company accounts for the Swap arrangements as hedging activities and, accordingly, gains or losses are included in oil and gas revenues for the period the production was hedged. The Company recorded hedging gains of $2.7 million and $15.8 million in the years ended December 31, 1999 and 1998, respectively, associated with contracts in place during those periods. The Company's future exposure under the hedging instruments in place at December 31, 1999 (i.e. estimated future loss assuming that NYMEX prices remain at current levels) is estimated to be approximately $15.5 million ($16.9 million assuming extension options are exercised by the counterparty). At December 31, 1999, the Company had $6.0 million in collateral associated with the above contracts on deposit with the counterparty. This cash collateral is included in Other Current Assets. The Company is required to 17 21 increase the amount of the deposit to the extent that the market price of oil and gas is higher than the contract price. Subsequent to the year-end the Company made additional deposits of $4 million. As an additional hedge on natural gas prices, the Company has also committed to fixed prices on approximately 26 MMCF per day, or 18%, of its estimated first quarter 2000 natural gas production at an average price of $2.69 per Mcf under existing sales contracts with the Company's purchaser of physical production. The Company may enter into additional arrangements in the future as part of its strategy to reduce exposure to commodity price fluctuations. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board 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, 2001. The Company is currently evaluating the impact of SFAS No. 133. 18 22 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) DOCUMENTS INCLUDED IN THIS REPORT: 1. FINANCIAL STATEMENTS

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: 2.1 First Amended Joint Plan of Reorganization of Forcenergy Inc and Forcenergy Resources Inc. dated October 26, 1999. (Filed as Exhibit 2.1 to the Company's Form 8-K filed on January 26, 2000 and incorporated herein by reference). 2.2 Motion for Authority to File Debtors' Second Immaterial Modification. (Filed as Exhibit 2.2 to the Company's Form 8-K filed on January 26, 2000 and incorporated herein by reference). 2.3 Debtors' Joint Plan Supplement dated November 8, 1999 (forms of reorganization documents). (Filed as Exhibit 2.3 to the Company's Form 8-K filed on January 26, 2000 and incorporated herein by reference). 2.4 Motion to Substitute Revised Warrant Agreements to be Filed as Part of Debtor's Amended Plan Supplement dated December 10, 1999. (Filed as Exhibit 2.4 to the Company's Form 8-K filed on January 26, 2000 and incorporated herein by reference). 2.5 Findings of Fact and Conclusions of Law and Order Confirming the Joint Plan of Reorganization of Forcenergy Inc and Forcenergy Resources Inc. dated January 19, 2000. (Filed as Exhibit 2.5 to the Company's Form 8-K filed on January 26, 2000 and incorporated herein by reference). 3.1 Amended and Restated Certificate of Incorporation of Forcenergy Inc dated as of February 15, 2000. (Filed as Exhibit 3.1 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 3.2 Amended and Restated Bylaws of Forcenergy Inc dated as of February 15, 2000. (Filed as Exhibit 3.2 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 4.1 Specimen Common Stock Certificate. (Filed as Exhibit 4.1 to the current report on Form 8-K filed on February 16, 2000 and incorporated herein by reference).

19 23 4.2 Certificate of Designation of the Powers Preferences and Relative, Participating, Optional and other Special Rights of 14% Series A Cumulative Preferred Stock. (Filed as Exhibit 4.2 to the current report on Form 8-K filed on February 16, 2000 and incorporated herein by reference). 4.3 Specimen 14% Series A Cumulative Preferred Stock Certificate. (Filed as Exhibit 4.3 to the current report on Form 8-K filed on February 16, 2000 and incorporated herein by reference). 4.4 Warrant Agreement (Four Year Warrants), dated as of February 15, 2000 between Forcenergy Inc and American Stock Transfer and Trust Company, including the form of Warrant Certificate for the Four Year Warrants. (Filed as Exhibit 4.4 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 4.5 Warrant Agreement (Five Year Warrants), dated as of February 15, 2000 between Forcenergy Inc and American Stock Transfer and Trust Company, including the form of Warrant Certificate for the Five Year Warrants. (Filed as Exhibit 4.5 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 4.6* Warrant Agreement (Subscription Warrants), dated as of March 20, 2000 between Forcenergy Inc and American Stock Transfer and Trust Company, including the form of Warrant Certificate for the Subscription Warrants. 10.1 Forcenergy Inc 1999 Stock Plan. (Filed as Exhibit 10.1 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.2 Forcenergy Inc 1999 Employee Stock Purchase Plan. (Filed as Exhibit 10.2 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.3 Registration Rights Agreement dated as of February 15, 2000 among Forcenergy Inc and the parties identified on the signature pages thereto. (Filed as Exhibit 10.3 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.4 Employment Agreement dated as of February 15, 2000 between Forcenergy Inc and Stig Wennerstrom. (Filed as Exhibit 10.4 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.5 Employment Agreement dated as of February 15, 2000 between Forcenergy Inc and J. Russell Porter. (Filed as Exhibit 10.5 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.6 Employment Agreement dated as of February 15, 2000 between Forcenergy Inc and Thomas F. Getten. (Filed as Exhibit 10.6 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.7 Employment Agreement dated as of February 15, 2000 between Forcenergy Inc and E. Joseph Grady. (Filed as Exhibit 10.7 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.8 Employment Agreement dated as of February 15, 2000 between Forcenergy Inc and Gary E. Carlson. (Filed as Exhibit 10.8 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.9 Employment Agreement dated as of February 15, 2000 between Forcenergy Inc and Mark Yelverton. (Filed as Exhibit 10.9 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.10 Employment Agreement dated as of February 15, 2000 between Forcenergy Inc and Robert G. Gerdes. (Filed as Exhibit 10.10 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 10.11 Employment Agreement dated as of December 10, 1999 between Forcenergy Inc and the Standby Purchasers named therein. (Filed as Exhibit 10.11 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference).

20 24 10.12 Credit Agreement dated as of February 15, 2000 between Forcenergy Inc, ING (U.S.) Capital LLC, as Agent and certain financial institutions named therein as Lenders. (Filed as Exhibit 10.12 to the Company's Form 8-K filed on February 16, 2000 and incorporated herein by reference). 21.1* Subsidiaries of the Company. 23.1* Consent of PricewaterhouseCoopers LLP 23.2* Consent of Netherland, Sewell & Associates, Inc. 23.3* Consent of Collarini Engineering Inc. 27.1* Financial Data Schedule

--------------- * Filed with original Annual Report on Form 10-K for the year ended December 31, 1999. b. REPORTS ON FORM 8-K No Current Reports on Form 8-K were filed by the Company during the fourth quarter of 1999. 21 25 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. Dated: November 3, 2000 FORCENERGY INC By: /s/ E. JOSEPH GRADY ------------------------------------ E. Joseph Grady Vice President -- Chief Financial Officer 22 26 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Forcenergy Inc 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 ("Successor") at December 31, 1999 and Forcenergy Inc. ("Predecessor") at December 31, 1998 (collectively, the "Company"), and the results of the Company's operations and cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. 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 auditing standards generally accepted in the United States, 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. As discussed in Notes 1 and 2 to the consolidated financial statements, on March 21, 1999, the Company filed a voluntary petition for relief, under Chapter 11 of Title 11 of the United States Code ("Chapter 11"), with the United States Bankruptcy Court for the Eastern District of Louisiana. The Company's Plan of Reorganization, as amended, became effective on February 15, 2000 and the Company emerged from Chapter 11. In connection with its emergence from Chapter 11, the Company adopted Fresh-Start Reporting as of December 31, 1999. PricewaterhouseCoopers LLP Miami, Florida March 17, 2000 F-1 27 FORCENERGY INC CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these financial statements. F-2 28 FORCENERGY INC CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these financial statements. F-3 29 FORCENERGY INC CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

The accompanying notes are an integral part of these financial statements. F-4 30 FORCENERGY INC CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these financial statements. F-5 31 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 -- ORGANIZATION AND BASIS OF PRESENTATION ORGANIZATION Forcenergy 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. The Company's principal areas of operation are the Gulf of Mexico and the Cook Inlet, Alaska. Forcenergy and its wholly-owned subsidiary Forcenergy Resources Inc. ("Resources") emerged from bankruptcy effective February 15, 2000 (See Note 2 for a more detailed discussion on the reorganized entity). The original voluntary petition for relief under Chapter 11 of Title 11 of the United States Code was filed on March 21, 1999 (the "Petition Date") in order to facilitate the restructuring of the Company's long-term debt, revolving credit, trade debt and other obligations. The filing was made in the United States Bankruptcy Court for the Eastern District of Louisiana in New Orleans (the "Bankruptcy Court"). While the Company operated under Chapter 11, certain claims against the Company at the Petition Date were stayed while the Company continued its operations as a debtor-in-possession. On January 19, 2000, the Bankruptcy Court approved the Company's Plan of Reorganization (the "Plan"), which became effective on February 15, 2000 (the "Emergence Date"). The consolidated financial statements as of December 31, 1999 and for the year then ended included herein reflect accounting principles set forth in the American Institute of Certified Public Accountants Statement of Position 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," ("SOP 90-7"), which provides guidance for financial reporting by entities that have filed voluntary petitions for relief under, and have reorganized in accordance with, the Bankruptcy Code. In accordance with guidance provided by SOP 90-7 the consummation of the Plan (the "Reorganization") has been reflected as though effective on December 31, 1999 (the "Effective Date"). Under provisions of SOP 90-7 and fresh start reporting (See Note 2) the December 31, 1999 Consolidated Balance Sheet is the opening balance sheet of the reorganized company (the "Successor Company"). The December 31, 1999 Consolidated Balance Sheet includes all adjustments necessary to reflect assets at reorganization value and the Plan's treatment of creditor claims and previous equity interests. Since the December 31, 1999 Consolidated Balance Sheet was affected by the Reorganization and fresh-start reporting adjustments, it is not comparable in certain material respects to any of the consolidated balance sheets shown in these financial statements as of any prior date. The Consolidated Statements of Operations and Cash Flows for the years ended December 31, 1999, 1998 and 1997 each reflect the activities of the Company prior to the Effective Date (the "Predecessor Company"), however, the statements for 1999 do reflect certain Reorganization-related charges and credits. NOTE 2 -- REORGANIZATION AND FRESH-START REPORTING In August 1999, the Company filed with the Bankruptcy Court a disclosure statement that included the proposed Plan. The Plan set forth the means for satisfying claims, including liabilities subject to compromise and equity interests in the Company. The disclosure statement was approved by the bankruptcy court on October 22, 1999, and the Plan was confirmed by the bankruptcy court on January 19, 2000. F-6 32 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The principal categories of claims classified as liabilities subject to compromise were as follows:

-------------------- * Prior to Effective Date The Plan segregated the above pre-petition liabilities into various secured and unsecured classifications for treatment according to priority of claim and subject to elections available to certain classes of claims. Secured trade claimants included in accounts payable and accrued liabilities received or will receive either cash payments (of between 80-100% of their claim, depending on priority), or a 3 1/2 year interest-bearing trade note payable. Holders of unsecured claims will receive common stock of the Successor Company (the "New Common Stock"). On February 15, 2000, the Company issued 23,040,000 shares of New Common Stock in exchange for all of the outstanding 8.5% and 9.5% Senior Subordinated Notes, collectively (the "Senior Subordinated Notes"), including unpaid interest accrued through the Petition Date thereon of $8.4 million. The difference between the fair market value of the New Common Stock issued and the recorded amount of the unsecured claims, including deferred financing costs, resulted in a gain on discharge of indebtedness of $160 million included as an extraordinary item in the Statement of Operations for the year ended December 31, 1999. The unsecured claimants were also entitled to participate in the rights offering discussed below. On February 15, 2000, the Company and its existing bank lending group entered into a new senior credit facility (the "New Senior Credit Facility") that replaced the Company's prior senior credit facility (the "Prior Senior Credit Facility") and satisfied all pre-petition claims thereunder. Pursuant to provisions of the Plan and the New Senior Credit Facility the Company paid $66.9 million in cash on the Effective Date to the bank group, which included a repayment of $40 million in principal outstanding under the Prior Senior Credit Facility, $24.3 million in accrued interest, and loan fees and administrative expenses incurred by the bank group of $2.6 million. The $2.6 million of administrative expenses were accrued at December 31, 1999, and were included as reorganization items in the Consolidated Statement of Operations for the year ended December 31, 1999. In accordance with provisions of the Plan, all outstanding shares of the common stock of the Predecessor Company (the "Old Common Stock") were canceled effective as of the Emergence Date and the holders of Old Common Stock as of the January 28, 2000 record date received, on a pro-rata basis. 960,000 shares of New Common Stock and associated warrants to purchase 240,000 shares of New Common Stock at $16.67 per share (expiring on February 15, 2004) and warrants to purchase 240,000 shares of New Common Stock at $20.83 per share (expiring on February 15, 2005). The cancellation and issuance of these equity instruments was reflected in the Successor Company consolidated Balance Sheet and the Consolidated Statement of Stockholder's Equity at December 31, 1999. The Plan also provides for the payment of administrative costs incurred during the pendency of the Reorganization (primarily legal and financial advisory fees). The Company paid $5.0 million in administrative expenses during 1999 and accrued another $11.2 million at December 31, 1999, all of which are included in the Consolidated Statement of Operations for the year ended December 31, 1999, as a reorganization item. F-7 33 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Plan required the Company to raise $40 million in additional equity capital. This was to be accomplished through a rights offering to unsecured claimants to purchase units that include one share of 14% Series A Cumulative Preferred Stock (the "Preferred Stock") and a warrant (the "Subscription Warrants") to purchase 45 shares of New Common Stock (collectively, the "Rights Offering") for $1,000 per unit. On March 20, 2000 the Rights Offering was closed with the issuance of 40,000 shares of Preferred Stock and Subscription Warrants to purchase 1,800,000 shares of New Common Stock. The net proceeds from the Rights Offering aggregated $38.8 million, net of offering costs of $1.2 million. The proceeds were used to pay down amounts outstanding under the New Senior Credit Facility (see proforma later in this footnote). The Preferred Stock is perpetual in nature and quarterly dividends are payable commencing March 31, 2000 in additional shares of Preferred Stock for the first four years thereafter. The Preferred Stock is non-convertible, and is callable by the Company at any time for 100% of liquidation preferences plus accrued but unpaid dividends. Holders of each share of Preferred Stock are entitled to one vote in matters requiring shareholder approval and vote as one class with the common shareholders. Only upon certain types of changes in control, the Company must redeem all outstanding Preferred Stock at 101% of liquidation preference plus accrued and unpaid dividends. The Subscription Warrants entitle the holder to purchase shares of New Common Stock at an initial exercise price of $10.00 per share. The Subscription Warrants are detachable and expire on March 15, 2010 or upon notice of expiration by the Company after March 20, 2004 if the market price of the New Common Stock has exceeded the exercise price of the Subscription Warrants for a period of 30 consecutive trading days. If the Company fails to pay a dividend for any two consecutive quarters or any six quarters in the aggregate, the holders of the Preferred Stock voting as a single class shall be entitled to elect two members of the board of directors. The terms of the Preferred Stock include other events of default, representations and warranties and affirmative and negative covenants typical for instruments of this type. Pursuant to the guidance provided by SOP 90-7 the Company adopted the provisions of fresh-start reporting and as discussed earlier the Reorganization was reflected at December 31, 1999. Under fresh-start reporting, the overall fair market value of the Company ("Reorganization Value") was allocated to the Successor Company's net assets using the purchase method of accounting. The Reorganization Value of $678.3 million was developed by the Company and the Company's independent financial advisors and represents the fair market value of working capital and the Company's oil and gas reserves. That value, less the New Senior Credit Facility, results in an equity value of $240 million. Working capital assets and liabilities of the Company at any given time as reflected in the consolidated financial statements are stated at fair market value. The methodologies used in the valuation of oil and gas reserves were the discounted cash flow ("DCF") and the Comparable Transactions Methods. The DCF valuation is based on the present value of the pre-tax cash flows from the Company's reserves discounted at 10% using escalated pricing consistent with the New York Mercantile Exchange ("NYMEX") futures curve, as of August 12, 1999 through 2001 and held flat thereafter at approximately $18.00 per barrel for oil and $2.50 per million cubic feet for gas. Cash flow has been risk adjusted and discounted based on industry accepted factors for reserves valuation. The DCF value of $510 million was compared to observed 1999 transaction values by region (Comparable Transactions Method) and deemed to be in a reasonable range of value for present industry conditions. Reorganization Value was less than the recorded amount of net assets immediately prior to emergence by $56.0 million, which was reflected as a revaluation of assets to fair market value under reorganization items in the Statement of Operations for the year ended December 31, 1999. See fresh-start reporting adjustment (b) below. F-8 34 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The effects of the Reorganization and related fresh-start reporting adjustments at December 31, 1999, are shown in the following consolidated balance sheet. Also presented is a proforma presentation as if all of the financing transactions and claims settlements incorporated in the Plan of Reorganization had been consummated as of December 31, 1999:

Reorganization and Fresh Start reporting adjustments: (a) Discharge of indebtedness. (b) Revaluation of the Company's oil and gas properties to fair market value. (c) Elimination of deferred financing costs associated with Prior Senior Credit Facility. (d) Establish the New Senior Credit Facility. (e) Cancellation of the Old Common Stock and elimination of accumulated deficit. (f) Issuance of 24 million shares of New Common Stock. Proforma Adjustments: (a) Issuance of Redeemable Preferred Stock and Subscription Warrants. (b) Satisfaction of remaining pre-petition claims. (c) Payment of accrued reorganization expenses. (d) Payment of accrued interest and principal on the New Senior Credit Facility. F-9 35 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 3 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The accompanying consolidated financial statements include the accounts of Forcenergy Inc, and its 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. The allowance for doubtful accounts was $2,000,000 at December 31, 1999 and 1998. 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 gain or loss is 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 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 F-10 36 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. Under the provisions of fresh-start reporting the Company restated its oil and gas properties to fair market value ($510 million) at December 31, 1999 resulting in a non-cash charge to the Consolidated Statement of Operations for the year ended December 31, 1999 of approximately $54 million, which is reflected as a reorganization item (See Note 2). During the fourth quarter of 1998 and 1997 the Company recognized non-cash impairments 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. REVENUE RECOGNITION During 1999, 1998 and 1997, 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 10). 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 prior to the Petition Date were cancelled during 1999 at the option of the counterparties subsequent to the Chapter 11 bankruptcy filing. The Company has subsequently entered into new contracts in 1999 and 2000 (See Note 10). 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 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 8). 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 9). F-11 37 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board 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. SFAS No. 133 will become effective with respect to the Company on January 1, 2001. The Company is currently evaluating the impact of SFAS No. 133. NOTE 4 -- ACQUISITIONS AND MERGERS The company had no material property acquisitions in 1999 during the pendency of the bankruptcy proceedings. 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. 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 its interest in this field to 100%. F-12 38 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. FORCENERGY AB ACQUISITION On December 19, 1997 Forcenergy made a public tender offer for all of the outstanding shares of Forcenergy AB ("FAB"). FAB was formed in 1990 to provide capital for Forcenergy's oil and gas operations in the United States and held 8,740,486 shares of Forcenergy common stock, its only significant asset. During 1998, the Company 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 1997) in exchange for the tendered shares. The 8,740,486 Forcenergy shares owned by FAB were controlled by Forcenergy, and for accounting and voting purposes were no longer considered outstanding. The acquisition was accounted for as a purchase with results of operations included beginning March 31, 1998. During the fourth quarter of 1999, the Company sold all of the outstanding shares of FAB for $5.5 million in cash, resulting in a gain on the sale of $5.5 million, which is included in interest and other income in the Consolidated Statement of Operations for the year ended December 31, 1999. The Forcenergy shares held by FAB discussed above were cancelled pursuant to the transaction. NOTE 5 -- PROPERTY, PLANT AND EQUIPMENT Investments in property, plant and equipment at December 31, 1999 and 1998 were as follows (in thousands):

Depletion, depreciation, and amortization for the years ended December 31, 1999, 1998 and 1997 was $116.4 million, $420.9 million (including a $275 million impairment (See Note 3)) and $313.3 million (including a $200 million impairment (See Note 3)), respectively. Under the provisions of fresh-start accounting the Company restated oil and gas properties and office equipment to fair market value at December 31, 1999 (See Notes 1 and 2). 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, 1999, 1998 and 1997 were $6.45, $6.84 (exclusive of impairment) and $6.36 (exclusive of impairment), respectively. Included in property, plant and equipment are capitalized internal costs relating to oil and gas property acquisition, exploration and development costs of $7.5 million, $10.2 million and $7.9 million for the years ended December 31, 1999, 1998 and 1997, respectively. F-13 39 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) During the years ended December 31, 1999, 1998 and 1997 the Company capitalized interest of $2.2 million, $4.4 million and $4.2 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 during which 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, 1999 and 1998 (in thousands):

At December 31, 1999, approximately 27% of excluded costs relate to offshore activities in the Gulf of Mexico and 73% relate to offshore activities in Alaska. 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 6 -- DEBT Long-term debt consists of the following at December 31, 1999 and 1998 (in thousands):

PRIOR SENIOR CREDIT FACILITY During 1998, the Company renegotiated, and subsequently amended, the Prior Senior Credit Facility to increase both the maximum loan amount and the borrowing base to $320 million with subsequent mandatory decreases to $300 million on May 1, 1999, and to $275 million on September 1, 1999. The mandatory decreases were stayed by the bankruptcy filing in March 1999. The Prior Senior Credit Facility provided for borrowings on a revolving basis through March 31, 2002, at which time all outstanding amounts under the Facility became due and payable. Advances bore interest at either the prime rate or a Fixed Rate (as defined in the agreement), at the election of the Company. Commitment fees on the unused portion of the Prior Senior Credit Facility were due quarterly at annual rates between .375% and 0.5%. The borrowing base was subject to redetermination semi-annually based on revised reserve estimates. The loan was secured by substantially all of the Company's oil and gas properties. At December 31, 1999 the Company had drawn down $314.5 million under the Prior Senior Credit Facility and an additional $5.4 million of availability was utilized for outstanding letters of credit issued under the Prior Senior Credit Facility. The Prior Senior Credit Facility contained certain covenants, which included maintenance of minimum tangible net worth, certain financial ratios, restrictions on asset sales, affiliated transactions and compensation and certain limitations on F-14 40 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) dividends and additional debt or liens. The Company was in violation of several of the financial covenants as of December 31, 1999 and 1998. As discussed in Note 1, all amounts drawn under the Prior Senior Credit Facility at December 31, 1998, were shown as liabilities subject to compromise pursuant to the Chapter 11 filing. Pursuant to the Reorganization the Company and substantially the same bank lending group entered into the New Senior Credit Facility on February 15, 2000, replacing the Prior Senior Credit Facility (See Notes 1 and 2). NEW SENIOR CREDIT FACILITY The New Senior Credit Facility consists of a $250 million Revolving Credit Facility (the "Revolver") and a $70 million Term Loan (the "Term Loan"). The amount that can be borrowed under the Revolver is further subject to a borrowing base which has been established at $250 million through February 15, 2001. The Revolver provides for borrowings on a revolving basis through August 15, 2003 at which time all outstanding amounts under the Revolver become due and payable. Advances under the Revolver bear interest at prime plus 1.5% or LIBOR plus 2% per annum at the election of the Company. The agreement provides for a commitment fee on the unused portion of the Revolver at .50% due quarterly. The borrowing base is subject to semi-annual re-determination after the first re-determination on February 15, 2001. The terms of the Term Loan provide mandatory quarterly principal repayments of $2.5 million commencing on March 31, 2001, with a $50 million balloon repayment at maturity on August 15, 2003. Interest is payable monthly at the prime rate plus 3% or LIBOR plus 3.5%. At March 28, 2000 the Company had drawn down $164.1 million under the Revolver under the New Senior Credit Facility and an additional $5.4 million of availability was utilized for outstanding letters of credit issued under the Revolver, leaving $80.5 million available for general corporate purposes. The New Senior Credit Facility is secured by substantially all of the Company's oil and gas properties and contains events of default, representation and warranties and covenants typical for facilities of this type. SENIOR SUBORDINATED NOTES On February 15, 2000, but effective December 31, 1999 for purposes of these financial statements, all of the outstanding Senior Subordinated Notes were exchanged for New Common Stock pursuant to the Reorganization (See Notes 1 and 2). In accordance with SOP 90-7 the Company did not accrue interest on the Senior Subordinated Notes after the Petition Date as it was unlikely such interest would be paid under the Plan. The amount of such unaccrued contractual interest from March 21, 1999, to December 31, 1999, was $26.2 million. The holders of the Notes did not pursue this interest as a part of their claims. 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") that matured on November 1, 2006. The 9 1/2% Notes were issued under an Indenture which provided that interest was payable semiannually, in arrears, on May 1 and November 1 of each year, commencing May 1, 1997, with principal due at maturity. 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"), that matured on February 15, 2007. The 8 1/2% Notes were issued under an Indenture which provided that interest on the 8 1/2% Notes was payable in cash in arrears semiannually on February 15 and August 15 of each year, commencing August 15, 1997 with principal due at maturity. F-15 41 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company's aggregate long-term debt maturities for the next five calendar years under the New Senior Credit Facility are as follows (in thousands): 2000...................................................... $ -- 2001...................................................... 10,000 2002...................................................... 10,000 2003...................................................... 294,473 -------- Total............................................. $314,473 ========

NOTE 5 -- INCOME TAXES The Company's benefit for income taxes is as follows (in thousands):

The Company's deferred income tax assets were comprised of the following differences between financial and tax reporting at December 31, 1999 and 1998 (in thousands):

At December 31, 1999 and 1998, the Company had approximately $115 million and $160 million, respectively, of deferred tax assets available to offset future taxable income for federal purposes. Valuation allowances have been provided against these deferred tax assets as it is assumed that more likely than not, the benefits will not be utilized. The Company continues to evaluate the realizability of its deferred tax assets and its estimate is subject to change. A reconciliation of the federal statutory income tax rates to the Company's effective rate is as follows:

At December 31, 1999, the Company had a net operating loss carryforward for tax purposes of $69.8 million. The net operating loss will expire unless otherwise utilized beginning in year 2000. The utilization of F-16 42 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) this carryforward is subject to limitations under the Internal Revenue Code. Section 382 of the Code provides for limitations on the utilization of available net operating loss carryforwards following a change in ownership. The Company's annual limitation on the utilization of its net operating losses is approximately $13.8 million. Deferred tax assets will not provide an income tax benefit when realized. Rather, the future realization of these assets will result in an increase in stockholders' equity. As a result of its reorganization under Chapter 11 of Title 11 of the United States Code, the Company realized cancellation of indebtedness income of approximately $171.1 million. Although this income is not taxable to the Company for federal or state tax purposes, the Company's net operating loss carryforwards were reduced by a corresponding amount. NOTE 8 -- 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 and warrants as the exercise price of all options granted was the fair market value on the date of grant. STOCK OPTION PLANS The following table summarizes the Predecessor Company's stock option activity for 1997, 1998 and 1999 under the 1995 Forcenergy Stock Option Plan, which was cancelled on February 15, 2000 in conjunction with the Reorganization (See Notes 1 and 2):

The 1999 cancellations occurred on February 15, 2000 in conjunction with the Reorganization which for accounting and reporting purposes, was considered effective on December 31, 1999 (See Notes 1 and 2). F-17 43 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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:

The weighted average fair value for options granted during 1999, 1998 and 1997 was $.41, $4.98 and $13.30, respectively, under the Black-Scholes model. For proforma purposes, the fair value of each option grant is estimated on the date of grant with the following weighted-average assumptions:

In February 1999, all options then outstanding were cancelled and reissued with an exercise price of $1.275 per share, the then current fair market value of the underlying 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. As a result of this repricing of options, the plan changed from a fixed option plan to a variable plan for accounting purposes. Effective February 15, 2000, the Company terminated the 1995 Stock Option Plan and adopted the Forcenergy Inc 1999 Stock Option Plan (the "1999 Stock Option Plan"), the terms of which are substantially the same as the canceled 1995 Forcenergy Stock Option Plan. Under the 1999 Stock Option Plan, options to purchase 3,000,000 shares of New Common Stock are available for issuance. Effective February 15, 2000, options to purchase approximately 1,328,000 shares of New Common Stock were issued and outstanding, with an exercise price of $10 per share. EMPLOYEE STOCK PURCHASE PLAN On February 15, 2000 the Company adopted the Forcenergy Inc 1999 Employee Stock Purchase Plan (the "Stock Purchase Plan") the terms of which are substantially the same as the previous employee stock purchase plan which was canceled on February 15, 2000 in conjunction with the Reorganization (See Notes 1 and 2). Up to 480,000 shares of New Common Stock are available to be sold to participants under terms of the Stock Purchase Plan. The Stock Purchase Plan permits full-time Company employees, or part-time employees meeting certain criteria, to purchase New Common Stock at a small discount from fair market value through payroll deductions. F-18 44 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 9 -- 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. NOTE 10 -- FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK The Company has historically entered into various financial instruments with off-balance-sheet risk, in the normal course of business, to reduce its exposure to changing commodity prices. The Company normally 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 for varying time periods. 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 on the Petition Date, all of which were cancelled at the option of the counterparties subsequent to the Company's bankruptcy filing. The Company received $5.5 million (fair market value of the contracts) in cash in April 1999, in final settlement of the contracts. The settlements were included in oil and gas sales in the Consolidated Statements of Operations for the year ended December 31, 1999. F-19 45 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company subsequently entered into several new financial hedging contracts ("Swaps") with respect to its future oil and natural gas production. 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. Swap contracts in place at December 31, 1999 and including contracts entered into after year-end on future oil production were as follows:

Swap contracts in place at December 31, 1999 on future natural gas production were as follows:

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-cost basis and are settled monthly. The Company accounts for the swap arrangements as hedging activities and, accordingly, gains or losses are included in oil and gas revenues for the period the production was hedged. The Company recorded hedging gains of $2.7 million and $15.8 million in the years ended December 31, 1999 and 1998, respectively, associated with contracts in place during those periods. The Company's future exposure under the hedging instruments in place at December 31, 1999 and including contracts entered into after year-end (i.e. estimated future loss assuming that NYMEX prices remain at current levels) is estimated to be approximately $15.5 million ($16.9 million assuming extension options are exercised by the counterparty). At December 31, 1999, the Company had $6.0 million in collateral associated with the above contracts on deposit with the counterparty. This cash collateral is included in Other current assets. The Company is required to increase the amount of the deposit to the extent that the market price of oil and gas is higher than the contract price. Subsequent to the year-end the Company made additional deposits of $4 million. As an additional hedge on natural gas prices, the Company has also committed to fixed prices on approximately 26 MMCF per day of its estimated first quarter 2000 natural gas production at an average price of $2.69 per Mcf under existing sales contracts with certain of the Company's purchasers of physical production. The Company may enter into additional arrangements in the future as part of its strategy to reduce exposure to commodity price fluctuations. F-20 46 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In June 1998 the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("Statement 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, 2001. The Company is currently evaluating the impact of the statement. NOTE 11 -- 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 were approximately $1.6 million, $2.0 million and $1.8 million for the years ended December 31, 1999, 1998 and 1997, respectively. NOTE 12 -- 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. NOTE 13 -- 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 1999, four 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 2000 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. F-21 47 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 14 -- CURRENT ASSETS AND LIABILITIES Current assets and liabilities include the following:

NOTE 15 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION During October 1997 Forcenergy acquired Edisto Resources Corporation and Convest Energy Corporation for Forcenergy Old Common Stock and cash balances Forcenergy received in the mergers. The accompanying financial statements include the following attributable to the Edisto and Convest mergers: Issuance of Old Common Stock................................ $98,934 Working capital acquired.................................... (4,196) ------- Total included in oil and gas properties.......... $94,738 =======

On March 31, 1998 the Company issued approximately 7.9 million shares of Old Common Stock valued at $27 per share pursuant to the tender offer for all of the outstanding common stock of FAB (See Note 4). The Company paid cash interest costs, including capitalized interest, of $14.2 million, $49.0 million, and $34.8 million for the years ended December 31, 1999, 1998 and 1997, respectively. F-22 48 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 16 -- SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)

--------------- (1) Includes the revaluation of assets to fair market value of $56.0 million, gain on discharge of indebtedness of $160.0 million and reorganization costs of $13.9 million (See Notes 1 and 2). (2) Includes $275 million non-cash impairment of oil and gas assets recorded in the fourth quarter of 1998 pursuant to the full cost accounting rules mandated by the Securities and Exchange Commission ("SEC"). NOTE 17 -- SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES COST INCURRED IN OIL AND GAS PRODUCING ACTIVITIES Presented below are costs incurred in petroleum property acquisition, exploration and development activities (in thousands):

F-23 49 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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):

Oil and gas properties were revalued to fair market value at December 31, 1999, pursuant to the Reorganization (See Notes 1 and 2). 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 1999 and 1998 financial hedging gains of $8.2 million and $15.8 million respectively, and 1997 financial hedging loss amounting to $10.8 million. (2) Net of effects of financial hedging and excluding the $5.5 million settlement on the cancellation of hedging contracts by the counterparties subsequent to the Companys filing of Chapter 11. (3) Includes condensate, crude oil and natural gas liquids. 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 proven 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 F-24 50 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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 incidence 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. F-25 51 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Predecessor Company's estimates of its proved reserves and proved developed reserves of oil and gas as of December 31, 1997, 1998 and 1999 and the changes in its proved reserves are as follows:

--------------- (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. F-26 52 FORCENERGY INC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Revisions to previous estimates for the year ended December 31, 1999 were primarily the result of higher prices as related to oil reserves and production declines on certain properties for gas reserves. For the year ended December 31, 1998 revisions to previous estimates were primarily the result of lower prices and the effect of those lower 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. 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:

F-27

FORCENERGY INC 10-K/A