<PAGE>   1
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                    FORM 10-K

[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 of other jurisdiction of                (I.R.S. Employer
          incorporation or organization)                Identification No.)


               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: None.


<PAGE>   2


                                   FORM 10-K
                                 FORCENERGY INC
                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
Item                                                                                                        Page
----                                                                                                        ----
<S>                                                                                                        <C>

                                                       PART I

   1    BUSINESS.........................................................................................     1
   2    PROPERTIES.......................................................................................    11
   3    LEGAL PROCEEDINGS................................................................................    13
   4    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............................................    13

                                                      PART II

   5    MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
        MATTERS..........................................................................................    14
   6    SELECTED FINANCIAL DATA..........................................................................    15
   7    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
           RESULTS OF OPERATIONS.........................................................................    16
   7A   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS......................................    21
   8    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA......................................................    21
   9    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
           FINANCIAL DISCLOSURE..........................................................................    21

                                                     PART III

  10    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...............................................    22
  11    EXECUTIVE COMPENSATION...........................................................................    22
  12    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT...................................    22
  13    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...................................................    22

                                                      PART IV

  14    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.................................    23

        GLOSSARY OF OIL AND GAS TERMS....................................................................    26

</TABLE>




                                      -1-
<PAGE>   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.


<PAGE>   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 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





                                      -1-
<PAGE>   5
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 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






                                      -2-
<PAGE>   6

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 Redobut 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 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.


                                      -3-
<PAGE>   7

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:

<TABLE>
<CAPTION>
                                                                       Estimated Net Proved Reserves At
                                                                               December 31, 1999
                                                                       ------------------------------
                                                     Average             Oil    Natural Gas    Total
                                                 Working Interest      (MBbls)     (MMcf)     (MMBOE)      Operator
                                                 ----------------      -------     ------     -------      --------
<S>                                                    <C>              <C>        <C>         <C>         <C>
South Marsh Island
     6/10/11/19/285 Complex:............              100%              2,264      37,865      8,575      Forcenergy
South Pass 24 Field.....................               71%              5,387      12,749      7,512      Third Party
South Marsh Island 137 Field,
     Block 136/137......................               50%              1,161      15,892      3,809      Forcenergy
East Cameron 14 Field...................              100%                537      18,503      3,621      Forcenergy
Vermilion 380 Field.....................              100%              1,617       7,336      2,840      Forcenergy
West Cameron 205 Field..................              100%                 92      15,010      2,594      Forcenergy
High Island A-552 Field.................              100%                528      10,699      2,312      Forcenergy
West Cameron 630 Field..................              100%                 21      13,650      2,297      Forcenergy
South Marsh Island Block 106 North
     and Block 106 South/Block 115 .....              100%                821       8,004      2,155      Forcenergy
Paradis Field...........................              100%              1,502       2,406      1,903      Forcenergy
High Island 195 Field...................               24%                 40       7,733      1,329      Forcenergy
Ship Shoal 26 Field Field...............              100%                239       5,804      1,206      Forcenergy
South Timbalier 76 Field, Block 148.....               16%                175       6,151      1,201      Third Party
Chandeleur 25 Field.....................              100%                  0       7,168      1,195      Forcenergy
Grand Isle 76 Field.....................              100%                105       5,994      1,104      Forcenergy
High Island A-467 Field.................              100%                 23       6,444      1,097      Forcenergy
Main Pass 69 Field......................               24%                285       4,766      1,079      Third Party


</TABLE>

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 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






                                      -4-
<PAGE>   8
 farmout acreage and to onshore undeveloped oil and natural gas leases upon
execution of the contracts. Prior to the commencement of drilling operations, a
thorough title examination is conducted and curative work is performed with
respect to significant defects. The Company performs complete reviews of title
to federal and state offshore lease blocks prior to acquisition. To the extent
title opinions or other investigations reflect material title defects, the
seller of the property, rather than the Company, is typically responsible for
curing any such title defects at its expense. If the Company were unable to
remedy or cure any title defect of a nature such that it would not be prudent to
commence drilling operations on undeveloped properties, the Company could suffer
a loss of its entire investment in the leasehold. The Company has obtained title
opinions on substantially all of its producing properties and believes that it
has satisfactory title to such properties in accordance with standards generally
accepted in the oil and gas industry. Substantially all of the Company's oil and
natural gas properties are mortgaged to secure borrowings under the Company's
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 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





                                      -5-
<PAGE>   9
 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 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, 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 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".




                                      -6-
<PAGE>   10

OPERATING RISKS OF OIL AND GAS OPERATIONS

         The oil and gas business involves certain operating hazards such as
well blowouts, cratering, explosions, uncontrollable flows of oil, natural gas
or well fluids, fires, formations with abnormal pressures, pollution, releases
of toxic gas and other environmental hazards and risks, any of which could
result in substantial losses to the Company through the loss of hydrocarbons,
pollution claims, personal injury suits and damage to properties of the Company
and others. The Company's offshore operations also are subject to the additional
hazards of marine operations, such as severe weather, capsizing and collision
that can cause substantial damage to facilities, and possible business
interruption. The availability of a ready market for the Company's oil and
natural gas production also depends on the proximity of reserves to, and the
capacity of, oil and gas gathering systems, pipelines and trucking or terminal
facilities. Additionally, the Company may be liable for environmental damages
caused by previous owners of property purchased or leased by the Company. As a
result, substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce or eliminate the funds available for
drilling or acquisitions, or result in the loss of the Company's properties. In
accordance with customary industry practices, Forcenergy maintains insurance
against some, but not all, of such risks and losses. The Company does not carry
business interruption insurance. The occurrence of an event not fully covered by
insurance could have a material adverse effect on the financial condition,
results of operations and cash flow of the Company.

ENVIRONMENTAL MATTERS

         The Company, as an owner or lessee and operator of oil and gas
properties, is subject to federal, state and local laws and regulations
governing the discharge of materials into, and the protection of, the
environment. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentration of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit drilling activities on
certain lands lying within wilderness, wetlands and other protected areas, and
impose substantial liabilities for pollution resulting from the Company's
operations. Stricter standards in environmental legislation may be imposed in
the oil and gas industry in the future, such as proposals made in Congress and
at the state level from time to time that would reclassify certain oil and
natural gas exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent and costly handling, disposal and
clean-up requirements. The impact of any such changes, however, would not likely
be any more burdensome to the Company than to any other similarly situated
company involved in oil and gas exploration and production.

         The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a hazardous
substance into the environment. These persons include the 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 indexing) for offshore
facilities of all removal costs plus $75,000,000. A





                                      -7-
<PAGE>   11

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 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.


                                      -8-
<PAGE>   12
         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 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.





                                      -9-
<PAGE>   13
 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.

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.









                                      -10-
<PAGE>   14


ITEM 2.   PROPERTIES

ACREAGE DATA

         The following table sets forth the approximate developed and
undeveloped acreage in which the Company held a leasehold, mineral or other
interest at December 31, 1999. Undeveloped acreage includes leased acres on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of whether or not
such acreage contains proved reserves.

<TABLE>
<CAPTION>
                                                      Developed Acres                Undeveloped Acres
                                                --------------------------      --------------------------
                                                   Gross            Net            Gross            Net
                                                ----------      ----------      ----------      ----------
<S>                                                <C>             <C>             <C>             <C>
         Offshore - Gulf of Mexico .......         584,405         265,553         117,427         114,693
         Offshore - Cook Inlet, Alaska ...          44,125          24,976         175,166         167,521
         Onshore - United States .........         326,816         104,682         642,835         112,695
         Australia (1) ...................           1,000             500      32,786,623      15,314,356
         Offshore - Gabon, Africa (1) ....              --              --       3,082,428       1,882,428
                                                ----------      ----------      ----------      ----------
           Total .........................         956,346         395,711      36,804,479      17,591,693
                                                ==========      ==========      ==========      ==========

</TABLE>

(1) The Company has various work/financial commitments that must be met on these
    concessions over the next two to three years in order to extend the life of
    each concession. These commitments vary by concession and could include
    geological studies, seismic operations and/or the drilling of a well. Should
    the Company fail to timely meet these commitments, or be granted an
    extension of time, it could be forced to relinquish its rights to that
    particular concession.

OIL AND GAS RESERVES

         The following table summarizes the estimates of the Company's
historical net proved reserves as of January 1, 2000 and the present values
attributable to those reserves on such date using constant prices and operating
costs as of the valuation date, discounted at a rate of 10% per annum, in
accordance with Securities and Exchange Commission ("Commission") guidelines.
The reserve data and present values as of January 1, 2000 for the onshore
properties have been estimated by Netherland, Sewell & Associates, Inc.,
independent petroleum engineering consultants. The reserve data and present
values as of January 1, 2000 for the offshore and Alaska properties have been
estimated by the Company. The offshore reserve data has been audited by
Collarini Engineering Inc., independent petroleum engineering consultants, and
the Alaska reserves have been audited by Netherland Sewell & Associates, Inc.

<TABLE>
<CAPTION>
                                                                                                As of
                                                                                           January 1, 2000
                                                                                           ---------------
<S>                                                                                             <C>
         NET PROVED RESERVES:
         Liquids(MBbls) (1) ..........................................................          64,959
         Natural gas (Mmcf) ..........................................................         300,616
                  Total (MBOE) .......................................................         115,062
         Future value of net cash flows before income taxes (thousands) ..............      $1,208,001
         Standardized measure of discounted future net cash flows (thousands) (2) ....      $  768,929

</TABLE>


(1)  Includes crude oil, condensate and natural gas liquids.

(2)  The standardized measure of discounted future net cash flows represents
     the present value of future net revenues after income taxes discounted
     at 10% in accordance with Statement of Financial Accounting Standards
     No. 69.

         Since January 1, 1999, the Company has not filed any estimates of
proved oil and gas reserves with any federal authority or agency other than with
the Commission and certain summary information with the Bankruptcy Court.




                                      -11-
<PAGE>   15


DRILLING ACTIVITY

         The following table sets forth the completed drilling activity of the
Company on its properties for the twelve-month periods ended December 31, 1999,
1998 and 1997.

<TABLE>
<CAPTION>
                                                                               YEAR ENDED DECEMBER 31,
                                                  ------------------------------------------------------------------------------
                                                            1999                      1998                         1997
                                                  ----------------------      ----------------------      ----------------------
                                                    Gross          Net          Gross         Net            Gross        Net
                                                  --------      --------      --------      --------      --------      --------
 <S>                                              <C>           <C>           <C>           <C>            <C>          <C>
         GULF OF MEXICO DRILLING ACTIVITY:
Development:
    Oil .....................................             1           1.0             1           0.1             3           2.7
    Gas .....................................             2            .1             2           0.4             6           4.1
    Non productive ..........................            --            --             1           0.3            --            --
                                                   --------      --------      --------      --------      --------      --------
         Total ..............................             3           1.1             4           0.8             9           6.8
                                                   ========      ========      ========      ========      ========      ========

Exploratory:
    Oil .....................................             3           2.1             1           1.0            --            --
    Gas .....................................             1            .1            12           7.4            21          13.2
    Non productive ..........................             2            .7             7           4.7            14          11.1
                                                   --------      --------      --------      --------      --------      --------
         Total ..............................             6           2.9            20          13.1            35          24.3
                                                   ========      ========      ========      ========      ========      ========

         ONSHORE DRILLING ACTIVITY:
Development:
    Oil .....................................            --            --            14           1.6             9           3.5
    Gas .....................................             4           1.2             3           0.6             2            .8
    Non productive ..........................             1            --*            3           1.7             2            .9
                                                   --------      --------      --------      --------      --------      --------
         Total ..............................             5           1.2            20           3.9            13           5.2
                                                   ========      ========      ========      ========      ========      ========

Exploratory:
    Oil .....................................            --            --             1           0.4            --            --
    Gas .....................................             3            .1            --            --             3           1.0
    Non productive ..........................             1            --*            2           0.6             2            .8
                                                   --------      --------      --------      --------      --------      --------
         Total ..............................             4            .1             3           1.0             5           1.8
                                                   ========      ========      ========      ========      ========      ========

         ALASKA DRILLING ACTIVITY:
Development:
    Oil .....................................             2           1.0             1           1.0             3           2.0
    Gas .....................................            --            --            --            --            --            --
    Non productive ..........................            --            --            --            --            --            --
                                                   --------      --------      --------      --------      --------      --------
    Total ...................................             2           1.0             1           1.0             3           2.0
                                                   ========      ========      ========      ========      ========      ========

Exploratory:
    Oil .....................................            --            --            --            --            --            --
    Gas .....................................            --            --            --            --            --            --
    Non productive ..........................            --            --             2           1.5            --            --
                                                   --------      --------      --------      --------      --------      --------
         Total ..............................            --            --             2           1.5            --            --
                                                   ========      ========      ========      ========      ========      ========

         INTERNATIONAL DRILLING ACTIVITY:
Development:
    Oil .....................................            --            --            --            --            --            --
    Gas .....................................            --            --            --            --            --            --
    Non productive ..........................            --            --            --            --            --            --
                                                   --------      --------      --------      --------      --------      --------
         Total ..............................            --            --            --            --            --            --
                                                   ========      ========      ========      ========      ========      ========

Exploratory:
    Oil .....................................            --            --            --            --             3           2.4
    Gas .....................................            --            --             2           1.6            --            --
    Non productive ..........................            --            --             5           3.0             6           4.2
                                                   --------      --------      --------      --------      --------      --------
         Total ..............................            --            --             7           4.6             9           6.6
                                                   ========      ========      ========      ========      ========      ========

</TABLE>

* Less than 5% working interest



                                      -12-
<PAGE>   16



PRODUCTIVE WELLS

         The following table sets forth the number of productive oil and gas
wells in which the Company owned a working interest at December 31, 1999:

                                     Total Productive Wells
                                     ----------------------
                                        Gross       Net
                                     --------    ----------
         Oil .....................      1,801        713
         Gas .....................        759        284
                                        -----      -----
            Total ................      2,560        997
                                        =====      =====

         Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. The Company has
21 wells that are completed in more than one producing horizon; those wells have
been counted as single wells.


ITEM 3.  LEGAL PROCEEDINGS

         On March 21, 1999, the Company and its wholly owned subsidiary,
Forcenergy Resources Inc., filed voluntarily under Chapter 11 of the U.S.
Bankruptcy Code in order to facilitate the restructuring of the Company's
long-term debt, revolving credit, trade and other obligations. The Company
continued to operate as a debtor-in-possession subject to the Bankruptcy Court's
supervision and orders until its Plan of Reorganization was confirmed on January
19, 2000 and became effective on February 15, 2000.


         The Company is a party to various claims and routine litigation arising
in the normal course of its business. Obligations of the Company in respect of
litigation arising out of activities prior to the Petition Date, will be
discharged in accordance with the Plan of Reorganization. Based on information
currently available, management of the Company believes, after consultation with
legal counsel, that the result of such claims and litigation, will not have a
material adverse effect on the financial position or results of operations of
the Company.


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

         There were no matters submitted to a vote of security holders during
the fourth quarter of the Company's fiscal year ended December 31, 1999. Through
the soliciation of proxies or otherwise, however, pursuant to an order of the
Bankruptcy Court, claimants of the Company, including equity holders, voted to
accept or reject the Plan of Reorganization.




                                      -13-
<PAGE>   17


                                    PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
         STOCKHOLDER MATTERS

         Prior to the Chapter 11 filing on March 21, 1999, the Company's
pre-reorganization common stock (the "Old Common Stock") was listed on the New
York Stock Exchange (the "NYSE") under the symbol "FEN". Prior to June 18, 1997,
the Company's Old Common Stock was quoted on the NASDAQ National Market (the
"NASDAQ") under the symbol "FGAS". On March 22, 1999, the NYSE suspended trading
in the Company's Old Common Stock because of the Chapter 11 bankruptcy filing.
The Company was then delisted. Forcenergy's Old Common Stock was then quoted on
the NASD OTC Bulletin Board under the trading symbols "FENYQ" and "FENYE". The
Company's New Common Stock (See Notes 1 and 2 to the Consolidated Financial
statements included elsewhere in this Form 10-K) was traded over the counter
under the symbol FORCV.OB until the "V" was dropped on March 29, 2000.

         The following table sets forth, for the periods indicated, the range of
closing high and low prices or bid quotations of the Company's Old Common Stock
as reported by the NYSE and the NASDAQ, respectively. The bid quotations, which
were obtained from NASDAQ Trading and Market Services, represent prices between
dealers without adjustment for retail mark-ups, mark-downs or commissions and
may not represent actual transactions.


<TABLE>
<CAPTION>
                                                                                            High          Low
                                                                                            ----          ---
<S>                                                                                      <C>           <C>
         1998 First Quarter.........................................................     $  27.13      $  21.25
              Second Quarter........................................................     $  27.06      $  15.25
              Third Quarter.........................................................     $  17.63      $   5.19
              Fourth Quarter........................................................     $   7.25      $   2.63
         1999 First Quarter.........................................................     $   3.19      $   0.62
              Second Quarter........................................................     $   1.69      $   0.72
              Third Quarter.........................................................     $   1.25      $   0.72
              Fourth Quarter........................................................     $   0.91      $   0.52

</TABLE>


         On March 28, 2000, the high and low bid quotations for the Company's
New Common Stock were both $14 on minimal trading.

         On March 26, 2000, the Company had approximately 6,000 shareholders of
record of its New Common Stock. The Company estimates that an additional 14,000
shareholders hold Forcenergy's New Common Stock in street name.

         In connection with the Company's Reorganization effective February 15,
2000, the Company issued 24,000,000 shares of New Common Stock, including
960,000 shares in exchange for all shares of then-outstanding Old Common Stock.

DIVIDEND POLICY

         The Company has paid no cash dividends in its last two fiscal years.
The Company was restricted under the terms of its borrowings, including its debt
instruments, from paying cash dividends on its Old Common Stock. The Company
does not expect to pay cash dividends on its New Common Stock for the
foreseeable future. Moreover, certain covenants set forth in the Company's
Senior Credit Facility restrict and/or limit the ability of the Company to pay
cash dividends.








                                      -14-
<PAGE>   18

ITEM 6.   SELECTED FINANCIAL INFORMATION


         The following table sets forth selected historical financial data for
the Company as of and for each of the periods indicated. From March 21, 1999
through February 15, 2000, the Company was operating under Chapter 11, which
afforded the Company protection from the claims of its creditors and caused the
Company to incur certain bankruptcy-related expenses including legal fees,
financial advisory fees and independent auditor fees. In connection with the
emergence from Chapter 11 the Company adopted the fresh start reporting at
December 31, 1999 and as a result the Company does not believe that its
consolidated balance sheet at December 31, 1999 is comparable to previous years
in certain material respects. The following data should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Company's financial statements included elsewhere in this
Form 10-K.


<TABLE>
<CAPTION>
                                                                                   Predecessor Company
                                                      -------------------------------------------------------------------------
                                                                           For the Years Ended December 31,
                                                      -------------------------------------------------------------------------
                                                        1999             1998           1997             1996           1995
                                                      ---------       ---------       ---------       ---------       ---------
                                                                         (in thousands, except per share amounts)
<S>                                                   <C>             <C>             <C>             <C>             <C>
INCOME STATEMENT DATA:
REVENUES:
     Oil and gas sales .........................      $ 265,824       $ 272,410       $ 281,690       $ 138,698       $  72,147
     Other .....................................            906           1,139           2,495             683             494
                                                      ---------       ---------       ---------       ---------       ---------
                                                        266,730         273,549         284,185         139,381          72,641
                                                      ---------       ---------       ---------       ---------       ---------
EXPENSES:
     Lease operating ...........................         87,009          99,242          77,174          38,786          24,507
     Depletion, depreciation and amortization ..        116,400         145,856         113,347          58,464          31,295
     Production taxes ..........................          4,512           4,218           4,791           3,454           1,868
     General and administrative ................         13,700          17,222          15,244           7,971           5,670
     Impairment of oil and gas properties ......             --         275,000         200,000              --              --
                                                      ---------       ---------       ---------       ---------       ---------
                                                        221,621         541,538         410,556         108,675          63,340
                                                      ---------       ---------       ---------       ---------       ---------

INCOME (LOSS) FROM OPERATIONS ..................         45,109        (267,989)       (126,371)         30,706           9,301
Other income ...................................          6,958           1,572           3,354             650            (561)
Interest expense, net of amounts capitalized ...        (32,270)        (48,077)        (32,422)        (13,367)        (11,668)
                                                      ---------       ---------       ---------       ---------       ---------
INCOME (LOSS) BEFORE REORGANIZATION ITEMS,
     INCOME TAXES AND EXTRAORDINARY ITEM .......         19,797        (314,494)       (155,439)         17,989          (2,928)
                                                      ---------       ---------       ---------       ---------       ---------

REORGANIZATION ITEMS:
     Interest income ...........................          2,293              --              --              --              --
     Professional and administrative fees ......        (16,205)             --              --              --              --
     Revaluation of assets to fair market value.        (56,005)             --              --              --              --
                                                      ---------       ---------       ---------       ---------       ---------
                                                        (69,917)             --              --              --              --
                                                      ---------       ---------       ---------       ---------       ---------
INCOME (LOSS) BEFORE INCOME TAXES &
     EXTRAORDINARY ITEM ........................        (50,120)       (314,494)       (155,439)         17,989          (2,928)
Income tax benefit (provision) .................             --              --          20,621          (6,711)          1,075
                                                      ---------       ---------       ---------       ---------       ---------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ........        (50,120)       (314,494)       (134,818)         11,278          (1,853)
Extraordinary item - gain on reorganization
     discharge of indebtedness .................        159,972              --              --              --              --
                                                      ---------       ---------       ---------       ---------       ---------
NET INCOME (LOSS) ..............................      $ 109,852      $ (314,494)     $ (134,818)      $  11,278       $  (1,853)
                                                      =========       =========       =========       =========       =========

PER COMMON SHARE:
NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM
     Basic .....................................      $   (2.02)      $  (12.65)      $   (5.83)      $     .60       $    (.14)
     Diluted ...................................      $   (2.02)      $  (12.65)      $   (5.83)      $     .57       $    (.14)
Extraordinary Item - gain on reorganization
     discharge of indebtedness
     (basic & diluted) .........................      $    6.46       $      --       $      --       $      --       $      --
Net income (loss):
     Basic .....................................      $    4.44       $  (12.65)      $   (5.83)      $     .60       $    (.14)
     Diluted ...................................      $    4.44       $  (12.65)      $   (5.83)      $     .57       $    (.14)

WEIGHTED AVERAGE SHARES OUTSTANDING:
    Basic ......................................         24,754          24,856          23,142          18,934          12,910
    Diluted ....................................         24,754          24,856          23,142          19,672          12,910

</TABLE>


                                      -15-
<PAGE>   19


<TABLE>
<CAPTION>
                                                                      |                    Predecessor Company
                                                         Successor    | ------------------------------------------------------------
                                                          Company     |                       December 31,
                                                         December 31, | ------------------------------------------------------------
                                                            1999      |       1998           1997            1996            1995
                                                         ---------    |    ---------       ---------       ---------      ---------
                                                                      |                  (in thousands)
<S>                                                      <C>          |    <C>             <C>             <C>            <C>
BALANCE SHEET DATA:                                                   |
    Working capital (deficit) .....................      $  35,772    |    $  49,791       $ (12,894)      $   8,035      $ (11,775)
    Total assets ..................................        675,401    |      678,468         824,230         585,925        335,090
    Total liabilities subject to compromise .......             --    |      778,720              --              --             --
    Long-term debt ................................        314,473    |           --         506,564         272,932        130,729
    Stockholders' equity (deficit) ................        240,000    |     (100,252)        214,991         248,936        154,961


</TABLE>

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:

<TABLE>
<CAPTION>
                                                                            Predecessor Company
                                                                  ------------------------------------------
                                                                              Year Ended December 31,
                                                                  ------------------------------------------
                                                                     1999             1998            1997
                                                                  ----------      ----------      ----------
<S>                                                                    <C>             <C>             <C>
         PRODUCTION:
           Liquids (MBbls) (1) .............................           7,877           8,513           8,210
           Natural gas (MMcf) ..............................          61,048          76,799          57,737
           Total (MBOE) ....................................          18,052          21,313          17,833
         AVERAGE REALIZED SALES PRICES (2):
           Oil (per Bbl) ...................................      $    15.62      $    12.72      $    17.57
           Plant products (per Bbl) ........................           12.41            8.78           13.57
           Liquids (per Bbl)(1) ............................           15.48           12.54           17.34
           Natural gas (per Mcf) ...........................            2.27            2.16            2.41
         EXPENSES (PER BOE):
           Lease operating .................................      $     4.82      $     4.66      $     4.33
           Depletion, depreciation and amortization (3) ....            6.45            6.84            6.36
           General and administrative, net .................             .76             .81             .85

</TABLE>


-------------

(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.



                                      -16-
<PAGE>   20


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).

         OPERATING INCOME/LOSS. For the year ended December 31, 1999, operating
income rose to $55.1 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






                                      -17-
<PAGE>   21

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
subsidary.

         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 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.

         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, 998, a 33% increase over the 57,737
MMcf produced in 1997. On an equivalent unit basis, 1998 production increased to
21,313 MBOE, 20% more than the 17,833 MBOE produced during 1997. The increase in
equivalent production resulted from producing properties in the Gulf of Mexico
acquired late 1997 and early 1998 and from the success of the Company's late
1997 and 1998 drilling and workover programs.

         REVENUES. Revenues were $273.5 million for the year ended December 31,
1998, compared to $284.2 million reported last year, as lower net realized
prices only partially offset by higher production volumes. Average net realized
liquid prices declined to $12.54 per Bbl in 1998, a 28% decrease compared with
$17.34 per Bbl received in 1997. Average net realized gas prices declined to
$2.16 per Mcf in 1998, a 10% decrease compared with $2.41 per Mcf reported in
1997.

         Average prices received for field production for 1998 were $11.59 per
Bbl and $2.06 per Mcf for liquids and natural gas, respectively. After taking
into account the effects of 1998 hedging activities entered into in order to
guarantee a certain level of cash flow from production, specifically an $8.0
million increase in liquids revenue and a $7.7 million increase in gas revenue,
net realized prices were $12.54 per Bbl and $2.16 per Mcf for liquids and
natural gas, respectively. All commodity price hedging contracts in place were
cancelled at the option of the counterparty pursuant to the filing under Chapter
11 of the U.S. Bankruptcy Code on March 21, 1999. The aggregate fair market
value of the cancelled contracts, approximately $5.5 million, was remitted to
the Company in April 1999. Average field prices for 1997 were $17.70 per Bbl and
$2.55 per Mcf for liquids and natural gas respectively. After taking into
account the effects of 1997 hedging activities, specifically a $2.9 million
reduction in liquids revenue and a $7.9 million reduction in gas revenue, net
realized prices were reduced to $17.34 per Bbl and $2.41 per Mcf for liquids and
natural gas, respectively.

         LEASE OPERATING EXPENSES. Lease operating expenses were $99.2 million
in 1998 compared to $77.2 million in 1997. The increase related primarily to new
oil and gas properties acquired in late 1997 and early 1998. On an equivalent
unit of production basis, lease operating expenses increased to $4.66 per BOE in
1998 from $4.33 per BOE in 1997, an increase attributable to slightly higher
lease operating expenses associated with new properties acquired and higher 1998
workover costs.

         DEPLETION, DEPRECIATION AND AMORTIZATION("DD&A"). DD&A expense
increased to $420.9 million in 1998 from $313.3 million for 1997. DD&A expense,
not including impairment provisions, was $145.9 million in 1998 compared to
$113.3 million in 1997. The increase was principally attributable to higher
production volumes and an increase in the rate from $6.36 per BOE in 1997 to
$6.84 per BOE in 1998. In addition, the Company recorded non-cash impairments of
oil and gas assets in the fourth quarter of 1998 for $275 million and $200
million in the fourth quarter of 1997.

         GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense,
net of overhead reimbursements and capitalized internal costs, was $17.2 million
in 1998 compared with $15.2 million in 1997. This increase was attributable to
the overall growth of the Company. On a barrel equivalent basis, general and
administrative expenses decreased by 5% to $.81 per BOE in 1998 from $.85 per
BOE in 1997.

         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).

         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






                                      -18-
<PAGE>   22
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:

<TABLE>
<CAPTION>
                                                                         (in thousands)
                                                               1999            1998            1997
                                                            ---------       ---------       ---------
<S>                                                         <C>             <C>             <C>
Net cash provided by operating activities before
     reorganization items ............................      $ 145,001       $ 141,853       $ 177,621
Borrowings under the prior senior credit facility ....         26,473         315,500         287,144
Repayments under the prior senior credit facility ....         (8,700)       (150,364)       (253,512)
Issuance of long-term debt, net of expenses ..........             --              --         193,414
Proceeds from sale of assets .........................         10,084          13,987              --


</TABLE>

         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.

         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.



                                      -19-
<PAGE>   23
         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:

<TABLE>
<CAPTION>
                                                                            Average
                                                 Volume in              NYMEX Contract
                                               Bbl's Per Day             Price Per Bbl
                                               -------------            ---------------
<S>                                            <C>                      <C>
         January 2000 - March 2000                 2,000                  $   21.85
         January 2000 - May 2000                   1,000                      21.56
         January 2000 - June 2000                  8,000                      19.28
         March 2000                                5,000                      30.05
         April 2000 - May 2000                     7,000                      28.58
         April 200 - June 2000                     2,000                      21.00
         June 2000                                 6,000                      27.02
         July 2000 - December 2000                12,000                      24.86


</TABLE>

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

<TABLE>
<CAPTION>
                                             Volume in             Weighted Average
                                                Mcf                 NYMEX Contract
                                              Per Day                Price Per Mcf
                                              -------              ----------------
<S>                                            <C>                   <C>
         January 2000                          40,000                  $   3.04
         February 2000                         40,000                      2.87
         April 2000 - June 2000               110,000                      2.63
         July 2000 - December 2000            100,000                      2.76

</TABLE>

         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 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 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.



                                      -20-
<PAGE>   24

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.


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

         Revenues generated from operations are highly dependent upon the price
of, and demand for, oil and natural gas. Historically, the markets for oil and
natural gas have been volatile and are likely to continue to be volatile in the
future as prices are subject to wide fluctuations in response to relatively
minor changes in the supply of and demand for oil and natural gas, market
uncertainty and a variety of additional factors that are beyond the control of
the Company. These uncontrollable factors include the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the
price and availability of alternative fuels and political and economic
conditions in the Middle East, Russia, Mexico and Canada that can affect the
supply and price of foreign oil and natural gas. It is impossible to predict
future oil and natural gas price movements with any certainty. Declines in oil
and natural gas prices may adversely affect the Company's financial condition,
liquidity and results of operations. Lower prices also may reduce the amount of
reserves that can be produced economically, as well as limit the ability to
continue to exploit and develop the existing reserve base.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

         The financial statements and schedules listed in Item 14 are included
in this Annual Report on Form 10-K beginning on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

         None.









                                      -21-
<PAGE>   25


                                    PART III

         Items 10, 11, 12 and 13 of Part III are incorporated herein by
reference from Forcenergy's Proxy Statement for the 2000 Annual Meeting of the
Stockholders, which is expected to be filed with the Securities and Exchange
Commission no later than April 29, 2000.
























                                      -22-
<PAGE>   26


                                    PART IV

ITEM 14.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)  DOCUMENTS INCLUDED IN THIS REPORT:

     1.  FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                                      Page
                                                                                                      ----
<S>                                                                                                    <C>
         Report of independent certified public accountants......................................     F-1
         Consolidated balance sheets as of December 31, 1999 and 1998............................     F-2
         Consolidated statements of operations for each of the three years in the period ended
           December 31, 1999.....................................................................     F-3
         Consolidated statements of stockholders' equity (deficit) for each of the three years
           in the period ended December 31, 1999.................................................     F-4
         Consolidated statements of cash flows for each of the three years in the period ended
           December 31, 1999.....................................................................     F-5
         Notes to consolidated financial statements..............................................     F-6

</TABLE>


     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).






                                      -23-
<PAGE>   27

         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).

         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).




                                      -24-
<PAGE>   28

         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).

         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 herewith.
         All other exhibits have been previously filed.


b.       REPORTS ON FORM 8-K

         No Current Reports on Form 8-K were filed by the Company during the
         fourth quarter of 1999.





                                      -25-
<PAGE>   29


                          GLOSSARY OF OIL AND GAS TERMS

         The definitions set forth below shall apply to the indicated terms as
used herein. All volumes of natural gas referred to herein are stated at the
legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.

         Bcf. Billion cubic feet.

         Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

         Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.

         BOPD. Barrels of oil per day.

         BOE.  Barrel of oil equivalent.

         Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

         Completion. The installation of permanent equipment for the production
of oil or gas, or in the case of a dry hole, the reporting of abandonment to the
appropriate agency.

         Developed acreage. The number of acres which are allocated or
assignable to producing wells or wells capable of production.

         Development well. A well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.

         Discounted Present Value. A method of determining the present value of
proved reserves. Under the SEC method, the future net revenues before income
taxes from proved reserves are estimated assuming that oil and natural gas
prices and production costs remain constant. The resulting stream of revenues is
then discounted at the rate of 10% per year to obtain the present value.

         Dry hole or well. A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

         Exploratory well. A well drilled to find and produce oil or gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or gas in another reservoir or to extend a known
reservoir.

         Farm-in or farm-out. An agreement whereupon the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in" while
the interest transferred by the assignor is a "farm-out."

         Field. An area consisting of single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.

         Gross acres or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.

         MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

         MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons
per day.




                                      -26-
<PAGE>   30

         Mcf. One thousand cubic feet.

         Mcfe. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.

         MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

         MMBtu. One million Btus.

         MMcf. One million cubic feet.

         MCFPD. One million cubic feet per day.

         Mmcfe. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.

         Net acres or net wells. The sum of the fractional working interests
owned in gross acres or gross wells.

         Oil. Crude oil and condensate.

         Present value. When used with respect to oil and gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect at the date indicated, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
future income tax expenses or to depreciation, depletion and amortization,
discounted using an annual discount rate of 10%.

         Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

         Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.

         Proved developed non-producing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.

         Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

         Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.

         Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required from recompletion.

         Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.

         Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.

         Royalty interest. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.






                                      -27-
<PAGE>   31

         Undeveloped acreage. Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether such acreage contains proved
reserves.

         Updip. A higher point in the reservoir.

         Working interest. The operating interest which gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production, subject to all royalties, overriding royalties and other
burdens and to all costs of exploration, development and operations and all
risks in connection therewith.

         Workover. Operations on a producing well to restore or increase
production.






                                      -28-
<PAGE>   32

                                   SIGNATURES


         Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                     FORCENERGY INC


Dated:   March 30, 2000              By: /s/ E. Joseph Grady
                                        --------------------------------------
                                        E. Joseph Grady
                                        Vice President - Chief Financial Officer


         Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons in the capacities and
on the dates indicated:


<TABLE>
<S>                                                                           <C>
By:  /s/ Stig Wennerstrom                                                     Date:  March 30, 2000
    ---------------------------------------------------
     Stig Wennerstrom
     President, Chief Executive Officer and
     Chairman of the Board of Directors
     (Principal Executive Officer)


By:  /s/ E. Joseph Grady                                                      Date:  March 30, 2000
    ---------------------------------------------------
     E. Joseph Grady
     Vice President - Chief Financial Officer
     (Principal Financial and Accounting Officer)


By:  /s/ Michael F. Bennet                                                    Date:  March 30, 2000
    ---------------------------------------------------
     Michael F. Bennet, Director


By:  /s/ Bruce L. Burnham                                                     Date:  March 30, 2000
    ---------------------------------------------------
     Bruce L. Burnham, Director


By:  /s/ B. James Ford                                                        Date:  March 30, 2000
    ---------------------------------------------------
     B. James Ford, Director


By:  /s/ Robert Issal                                                         Date: March 30, 2000
    ---------------------------------------------------
     Robert Issal, Director


By:  /s/ Clifford P. Hickey                                                   Date:  March 30, 2000
    ---------------------------------------------------
     Clifford P. Hickey, Director


By:  /s/ Stephen  A. Kaplan                                                   Date:  March 30, 2000
    ---------------------------------------------------
     Stephen A. Kaplan, Director


By:  /s/ Gregory P. Pipkin                                                    Date:  March 30, 2000
    ---------------------------------------------------
     Gregory P. Pipkin, Director

</TABLE>




                                      -29-
<PAGE>   33
                                     ITEM 8

                   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                           ANNUAL REPORT ON FORM 10-K

                      FOR THE YEAR ENDED DECEMBER 31, 1999

                                 FORCENERGY INC

                                 MIAMI, FLORIDA







<PAGE>   34

               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.



Miami, Florida
March 17, 2000



                                      F-1
<PAGE>   35


                                 FORCENERGY INC
                           CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
                                                                  Successor     |    Predecessor
                                                                   Company      |      Company
                                                                 ------------   |    ------------
                                                                 December 31,   |    December 31,
                                                                     1999       |       1998
                                                                 ------------   |    ------------
                                                               (in thousands)   |  (in thousands)
<S>                                                               <C>           |    <C>
ASSETS:                                                                         |
CURRENT ASSETS:                                                                 |
     Cash ..................................................      $  96,506     |    $   1,690
     Accounts receivable, net ..............................         41,332     |       28,433
     Other current assets ..................................         18,862     |       19,668
                                                                  ---------     |    ---------
         Total current assets ..............................        156,700     |       49,791
                                                                                |
PROPERTY, PLANT AND EQUIPMENT, at cost (full cost                               |
     method) net of accumulated depletion, depreciation                         |
     and amortization ......................................        512,000     |      610,948
                                                                                |
OTHER ASSETS ...............................................          6,701     |       17,729
                                                                  ---------     |    ---------
                                                                  $ 675,401     |    $ 678,468
                                                                  =========     |    =========
                                                                                |
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT):                                 |
LIABILITIES NOT SUBJECT TO COMPROMISE:                                          |
CURRENT LIABILITIES:                                                            |
     Accounts payable and accrued liabilities ..............      $ 120,928     |    $      --
                                                                  ---------     |    ---------
         Total current liabilities .........................        120,928     |           --
                                                                  ---------     |    ---------
                                                                                |
LIABILITIES SUBJECT TO COMPROMISE:                                              |
     Accounts payable and accrued liabilities ..............             --     |      107,020
     Long-term debt ........................................             --     |      671,700
                                                                  ---------     |    ---------
         Total liabilities subject to compromise ...........             --     |      778,720
                                                                  ---------     |    ---------
                                                                                |
LONG-TERM DEBT .............................................        314,473     |           --
                                                                  ---------     |    ---------
                                                                                |
COMMITMENTS AND CONTINGENCIES                                                   |
                                                                                |
STOCKHOLDERS' EQUITY (DEFICIT):                                                 |
     Preferred stock, $.01 par value; 5,000,000 shares                          |
         authorized; none issued or  outstanding ...........             --     |           --
     Common stock, $.01 par value; 50,000,000 shares                            |
         authorized; 24,000,000 and 24,747,445 issued                           |
         and outstanding at December 31, 1999 and                               |
         1998, respectively ................................            240     |          247
     Capital in excess of par value ........................        239,760     |      346,135
     Accumulated deficit ...................................             --     |     (446,634)
                                                                  ---------     |    ---------
         Total stockholders' equity (deficit) ..............        240,000     |     (100,252)
                                                                  ---------     |    ---------
                                                                  $ 675,401     |    $ 678,468
                                                                  =========     |    =========


</TABLE>



   The accompanying notes are an integral part of these financial statements.




                                      F-2
<PAGE>   36


                                 FORCENERGY INC
                      CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                                          Predecessor Company
                                                                    For the Year Ended December 31,
                                                             -----------------------------------------
                                                                1999            1998             1997
                                                             ---------       ---------       ---------
                                                             (in thousands, except per share amounts)
<S>                                                          <C>             <C>             <C>
REVENUES:
   Oil and gas sales ..................................      $ 265,824       $ 272,410       $ 281,690
   Other ..............................................            906           1,139           2,495
                                                             ---------       ---------       ---------
                                                               266,730         273,549         284,185
                                                             ---------       ---------       ---------
EXPENSES:
   Lease operating ....................................         87,009          99,242          77,174
   Depletion, depreciation and amortization ...........        116,400         145,856         113,347
   Production taxes ...................................          4,512           4,218           4,791
   General and administrative .........................         13,700          17,222          15,244
   Impairment of oil and gas properties ...............             --         275,000         200,000
                                                             ---------       ---------       ---------
                                                               221,621         541,538         410,556
                                                             ---------       ---------       ---------

INCOME (LOSS) FROM OPERATIONS .........................         45,109        (267,989)       (126,371)
Other income ..........................................          6,958           1,572           3,354
Interest expense, net of amounts capitalized ..........        (32,270)        (48,077)        (32,422)
                                                             ---------       ---------       ---------
INCOME (LOSS) BEFORE REORGANIZATION ITEMS,
   INCOME TAX BENEFIT AND EXTRAORDINARY ITEM ..........         19,797        (314,494)       (155,439)
                                                             ---------       ---------       ---------

REORGANIZATION ITEMS:
   Interest income ....................................          2,293              --              --
   Professional and administrative fees ...............        (16,205)             --              --
   Revaluation of assets to fair market value .........        (56,005)             --              --
                                                             ---------       ---------       ---------
                                                               (69,917)             --              --
                                                             ---------       ---------       ---------
INCOME (LOSS) BEFORE INCOME TAXES &
   EXTRAORDINARY ITEM .................................        (50,120)       (314,494)       (155,439)
Income tax benefit ....................................             --              --          20,621
                                                             ---------       ---------       ---------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ...............        (50,120)       (314,494)       (134,818)
Extraordinary item - gain on reorganization discharge of
   indebtedness .......................................        159,972              --              --
                                                             ---------       ---------       ---------
NET INCOME (LOSS) .....................................      $ 109,852       $(314,494)      $(134,818)
                                                             =========       =========       =========

PER COMMON SHARE:
   Net income (loss) before extraordinary item
      (basic & diluted) ...............................      $   (2.02)      $  (12.65)      $   (5.83)
   Extraordinary item - gain on reorganization discharge
      of indebtedness (basic and diluted) .............      $    6.46       $      --       $      --
   Net income (loss) (basic and diluted) ..............      $    4.44       $  (12.65)      $   (5.83)
   Weighted average shares outstanding (basic and
      diluted .........................................         24,754          24,856          23,142


</TABLE>

   The accompanying notes are an integral part of these financial statements.



                                      F-3
<PAGE>   37


                                 FORCENERGY INC
            CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)


<TABLE>
<CAPTION>

                                                      Common Stock                  Capital in                         Total
                                               -----------------------------        Excess of       Accumulated      Stockholders
                                                   Shares           Amount          Par Value         Deficit       Equity (Deficit)
                                               -----------       -----------       -----------       -----------    ----------------
                                                                 (in thousands, except shares)
<S>                                            <C>               <C>               <C>               <C>               <C>
BALANCE, JANUARY 1, 1997 ....................   22,577,838       $       226       $   246,032       $     2,678       $   248,936

Exercises of stock options and warrants .....      150,915                 1             2,503                --             2,504
Issuance of common stock ....................    2,775,864                28            98,341                --            98,369
Net loss ....................................           --                --                --          (134,818)         (134,818)
                                               -----------       -----------       -----------       -----------       -----------
BALANCE, DECEMBER 31, 1997 ..................   25,504,617               255           346,876          (132,140)          214,991
                                               -----------       -----------       -----------       -----------       -----------

Exercises of stock options ..................        3,675                --               187                --               187
Issuance of common stock ....................    7,979,639                80           214,203                --           214,283
Subsidiary investment in parent
      common stock ..........................   (8,740,486)              (88)         (215,131)               --          (215,219)
Net loss ....................................           --                --                --          (314,494)         (314,494)
                                               -----------       -----------       -----------       -----------       -----------
BALANCE, DECEMBER 31, 1998 ..................   24,747,445               247           346,135          (446,634)         (100,252)
                                               -----------       -----------       -----------       -----------       -----------

Issuance of common stock ....................        8,904                --                --                --                --
Net income ..................................           --                --                --           109,852           109,852
Cancellation of equity interests
     under plan of reorganization ...........  (24,756,349)             (247)         (346,135)          336,782            (9,600)
Issuance of equity interests under plan
     of reorganization ......................   24,000,000               240           239,760                --           240,000
                                               -----------       -----------       -----------       -----------       -----------
BALANCE, DECEMBER 31, 1999 (Successor Company)  24,000,000       $       240       $   239,760       $        --       $   240,000
                                               ===========       ===========       ===========       ===========       ===========



</TABLE>





   The accompanying notes are an integral part of these financial statements.




                                      F-4
<PAGE>   38



                                 FORCENERGY INC
                      CONSOLIDATED STATEMENTS OF CASH FLOWS


<TABLE>
<CAPTION>
                                                                                         Predecessor Company
                                                                                     For the Year Ended December 31,
                                                                              -----------------------------------------
                                                                                1999             1998            1997
                                                                              ---------       ---------       ---------
                                                                                           (in thousands)
<S>                                                                           <C>             <C>             <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
     Net income (loss) .................................................      $ 109,852       $(314,494)      $(134,818)
                                                                              ---------       ---------       ---------
     Adjustments to reconcile net income (loss) to net cash
       provided by operating activities before reorganization items:
     Reorganization items ..............................................         69,917              --              --
     Extraordinary item - gain on discharge of indebtedness ............       (159,972)             --              --
     Depletion, depreciation and amortization ..........................        117,835         145,856         113,347
     Impairment of oil and gas properties ..............................             --         275,000         200,000
     Deferred income taxes .............................................             --              --         (20,621)
     Sale of other assets ..............................................         (5,450)             --              --
     Other .............................................................           (320)          1,000            (223)
     (Increase) decrease in accounts receivable ........................        (12,899)         15,069             496
     (Increase) decrease in other current assets .......................           (770)         10,563         (18,597)
     Increase in accounts payable and accrued liabilities ..............         26,808           8,859          38,037
                                                                              ---------       ---------       ---------
                                                                                 35,149         456,347         312,439
                                                                              ---------       ---------       ---------
     Net cash provided by operating activities before
       reorganization items ............................................        145,001         141,853         177,621
     Reorganization items ..............................................        (69,917)             --              --
     Adjustments to reconcile reorganization items to cash used in
       reorganization items:
     Revaluation of assets to fair market value ........................         56,005              --              --
     Accrued reorganization expenses ...................................         11,236              --              --
                                                                              ---------       ---------       ---------
     Net cash used in reorganization items .............................         (2,676)             --              --
                                                                              ---------       ---------       ---------
Net cash provided by operating activities after
  reorganization items .................................................        142,325         141,853         177,621
                                                                              ---------       ---------       ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
     Acquisitions of oil and gas properties ............................         (1,234)        (53,956)       (119,503)
     Capital expenditures ..............................................        (76,110)       (283,475)       (287,229)
     Sale of surety bonds ..............................................             --              --           4,426
     Dividends from affiliate ..........................................             --           1,806             900
     Proceeds from sale of assets ......................................         10,084          13,987              --
     Change in other assets ............................................          1,978             (70)            457
                                                                              ---------       ---------       ---------
Net cash used in investing activities ..................................        (65,282)       (321,708)       (400,949)
                                                                              ---------       ---------       ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
     Borrowings under senior credit facility ...........................         26,473         315,500         287,144
     Repayments under senior credit facility ...........................         (8,700)       (150,364)       (253,512)
     Issuance of long-term debt, net of expenses .......................             --              --         193,414
     Issuance of common stock, net .....................................             --             361           2,661
                                                                              ---------       ---------       ---------
Net cash provided by financing activities ..............................         17,773         165,497         229,707
                                                                              ---------       ---------       ---------

NET INCREASE (DECREASE) IN CASH ........................................         94,816         (14,358)          6,379
CASH AT BEGINNING OF YEAR ..............................................          1,690          16,048           9,669
                                                                              ---------       ---------       ---------
CASH AT END OF YEAR ....................................................      $  96,506       $   1,690       $  16,048
                                                                              =========       =========       =========

</TABLE>

   The accompanying notes are an integral part of these financial statements.


                                      F-5
<PAGE>   39

                                 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.







                                      F-6
<PAGE>   40

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



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.

         The principal categories of claims classified as liabilities subject to
compromise were as follows:

<TABLE>
<CAPTION>
                                                              Predecessor Company
                                                             ----------------------
                                                                   December 31,
                                                             ----------------------
                                                               1999*          1998
                                                             --------      --------
<S>                                                          <C>           <C>
         Accounts payable and accrued liabilities ....       $ 72,532      $107,020
         9 1/2% Senior Subordinated Notes ............        175,000       175,000
         8 1/2% Senior Subordinated Notes ............        200,000       200,000
         Prior Senior Credit Facility ................       $314,473      $296,700
                                                             --------      --------
                                                             $762,005      $778,720
                                                             ========      ========

</TABLE>

         * 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.





                                      F-7
<PAGE>   41

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


         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 19, 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.

         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.





                                      F-8
<PAGE>   42

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


         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.

         The effects of the Reorganization and related fresh-start reporting
adjustments at December 31, 1999, are shown in the following consolidated
balance









                                      F-9
<PAGE>   43

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


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:



<TABLE>
<CAPTION>
                                             Predecessor                                   Successor
                                               Company                                     Company                       Proforma
                                             December 31,    Debt                        December 31,    Proforma      December 31,
                                                 1999     Discharge      Fresh-Start         1999      Adjustments         1999
                                             ----------   ---------      -----------     ------------  -----------     ------------
                                                                                                        Unaudited       Unaudited
<S>                                           <C>         <C>             <C>             <C>           <C>           <C>
ASSETS
CURRENT ASSETS:
  Cash ...................................... $  96,506   $      --       $      --       $  96,506     $  38,800 (a)   $     670
                                                                                                          (47,241)(b)
                                                                                                          (11,236)(c)
                                                                                                          (76,159)(d)
  Accounts receivable, net ..................    41,332          --              --          41,332            --          41,332
  Other current assets ......................    20,437     (1,461)(c)         (114)(b)      18,862            --          18,862
                                              ---------   ---------       ---------       ---------     ---------       ---------

    Total current assets ....................   158,275     (1,461)            (114)        156,700       (95,836)         60,864

PROPERTY, PLANT AND EQUIPMENT ...............   565,348          --         (53,348)(b)     512,000            --         512,000

OTHER ASSETS ................................    16,546     (7,302)(c)       (2,543)(b,c)     6,701         1,200(a)        7,901
                                              ---------   ---------       ---------       ---------     ---------       ---------


                                              $ 740,169   $ (8,763)       $ (56,005)      $ 675,401     $ (94,636)      $ 580,765
                                              =========   =========       =========       =========     =========       =========
LIABILITIES AND STOCKHOLDERS'
  (DEFICIT) EQUITY:
LIABILITIES NOT SUBJECT TO COMPROMISE:
CURRENT LIABILITIES:
  Accounts payable and accrued liabilities .. $ 120,928   $      --       $      --       $ 120,928     $ (47,241)(b)   $  41,534
                                                                                                          (11,236)(c)
                                                                                                          (20,917)(d)
                                              ---------   ---------       ---------       ---------     ---------       ---------
    Total liabilities not subject to
      compromise ............................   120,928          --              --         120,928       (79,394)         41,534
                                              ---------   ---------       ---------       ---------     ---------       ---------

LIABILITIES SUBJECT TO COMPROMISE:
CURRENT LIABILITIES:
  Accounts payable and accrued liabilities ..    24,135     (24,135)(a)          --              --            --              --
                                                                                                               --
  Long-term debt ............................   689,473    (375,000)(a)   (314,473)(d)           --            --              --
                                              ---------   ---------       ---------       ---------     ---------       ---------
    Total liabilities subject to compromise..   713,608    (399,135)      (314,473)              --            --              --
                                              ---------   ---------       ---------       ---------     ---------       ---------
LONG-TERM DEBT ..............................        --          --        314,473 (d)      314,473       (55,242)(d)     259,231
                                              ---------   ---------       ---------       ---------     ---------       ---------

REDEEMABLE PREFERRED STOCK ..................        --          --              --              --        29,038 (a)      29,038
                                              ---------   ---------       ---------       ---------     ---------       ---------

STOCKHOLDER'S (DEFICIT) EQUITY:
  Common stock ..............................       247         240 (f)        (247)(e)         240            --             240
  Capital in excess of par value ............   346,135        (240)(f)    (336,535)(e)     239,760        10,962 (a)     250,722
                                                            230,400 (a)
  Accumulated deficit .......................  (440,749)    159,972 (a)     (56,005)(b,c)        --            --              --
                                                                            336,782 (e)
                                              ---------   ---------       ---------       ---------     ---------       ---------
    TOTAL STOCKHOLDERS (DEFICIT) EQUITY .....   (94,367)    390,372         (56,005)        240,000        10,962         250,962
                                              ---------   ---------       ---------       ---------     ---------       ---------

                                              $ 740,169   $  (8,763)      $ (56,005)      $ 675,401     $ (94,636)      $ 580,765
                                              =========   =========       =========       =========     =========       =========


</TABLE>

Reorganization and Fresh Start reporting adjustments:







                                      F-10
<PAGE>   44

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



(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.

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






                                      F-11
<PAGE>   45

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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
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





                                      F-12
<PAGE>   46

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


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).

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.





                                      F-13
<PAGE>   47

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



("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%.

         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. FAB's
investment in the Forecenergy shares discussed above was cancelled pursuant to
the transaction.






                                      F-14
<PAGE>   48

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


NOTE 5 -- PROPERTY, PLANT AND EQUIPMENT

         Investments in property, plant and equipment at December 31, 1999 and
1998 were as follows (in thousands):

<TABLE>
<CAPTION>
                                                                                Successor   |   Predecessor
                                                                                 Company    |     Company
                                                                                  1999      |      1998
                                                                              -----------   |  -----------
<S>                                                                           <C>           |  <C>
         Oil and Gas Properties:                                                            |
                    Proved .............................................      $   450,000   |  $ 1,313,824
                    Unevaluated ........................................           60,000   |      165,885
                                                                              -----------   |  -----------
                                                                                  510,000   |    1,479,709
         Office Equipment ..............................................            2,000   |        9,809
         Less: accumulated depletion, depreciation and amortization ....               --   |     (878,570)
                                                                              -----------   |  -----------
         Net Property, Plant and Equipment .............................      $   512,000   |  $   610,948
                                                                              ===========   |  ===========

</TABLE>


         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.

         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):

<TABLE>
<CAPTION>
                                                 Successor  |  Predecessor
                                                  Company   |    Company
                                                    1999    |     1998
                                                  --------  |   --------
<S>                                               <C>       |   <C>
         Property Acquisition ..............      $ 43,743  |   $ 38,458
         Development Costs .................        16,257  |    121,983
         Interest Capitalized ..............            --  |      5,444
                                                  --------  |   --------
                                                  $ 60,000  |   $165,885
                                                  ========  |   ========


</TABLE>

         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.





                                      F-15
<PAGE>   49

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 6 -- DEBT

         Long-term debt consists of the following at December 31, 1999 and 1998
(in thousands):

<TABLE>
<CAPTION>
                                                    Successor  |  Predecessor
                                                     Company   |    Company
                                                       1999    |     1998
                                                     --------  |   --------
<S>                                                  <C>       |   <C>

         New Senior Credit Facility............      $314,473  |   $     --
         Prior Senior Credit Facility .........            --  |    296,700
         9 1/2% Senior Subordinated Notes .....            --  |    175,000
         8 1/2% Senior Subordinated Notes .....            --  |    200,000
                                                     --------  |   --------
                                                     $314,473  |   $671,700
                                                     ========  |   ========

</TABLE>

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 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%.


                                      F-16
<PAGE>   50

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



         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.

         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):

<TABLE>
<CAPTION>
                                                     Predecessor Company
                                                   Year Ended December 31,
                                        ---------------------------------------------
                                           1999             1998             1997
                                        -----------      -----------      -----------
<S>                                     <C>              <C>               <C>
         Deferred:
         Federal .................      $        --      $        --      $    17,929
         State ...................               --               --            2,692
                                        -----------      -----------      -----------
              Total ..............      $        --      $        --      $    20,621
                                        ===========      ===========      ===========

</TABLE>





                                      F-17
<PAGE>   51

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


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

<TABLE>
<CAPTION>
                                                                 Successor  |   Predecessor
                                                                  Company   |     Company
                                                                    1999    |       1998
                                                                 ---------  |    ---------
<S>                                                              <C>        |    <C>
              Capitalized costs and write-offs ............      $  88,540  |    $  99,898
              Net operating loss carryforwards ............         26,694  |       59,970
              Valuation allowance .........................       (115,234) |     (159,868)
                                                                 ---------  |    ---------
              Deferred tax liability ......................      $      --  |    $      --
                                                                 =========  |    =========

</TABLE>

         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:

<TABLE>
<CAPTION>
                                                                        Predecessor Company
                                                                      Year Ended December 31,
                                                            ----------------------------------------
                                                               1999            1998           1997
                                                            --------        --------        --------
<S>                                                         <C>             <C>             <C>
         Income taxes at federal statutory rates .....          35.0%           35.0%           35.0%
         State income tax, less federal benefit ......           3.3             3.3             3.3
         Valuation allowance .........................         (38.3)          (38.3)          (25.3)
         Other, net ..................................            --              --              .3
                                                            --------        --------        --------
         Total .......................................           0.0%            0.0%           13.3%
                                                            ========        ========        ========

</TABLE>

         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 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.





                                      F-18
<PAGE>   52

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


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):

<TABLE>
<CAPTION>
                                                             Number         Option Price     Weighted Average
                                                            of Shares         Per Share        Exercise Price
                                                          -----------     -----------------  ----------------
<S>                                                         <C>           <C>                     <C>
         Outstanding at December 31, 1996............       2,510,918     $ 10.00 - $ 32.00       $  15.25
         Granted.....................................       1,512,225       25.81 -   38.88          28.93
         Exercised...................................        (120,562)      10.00 -   26.88          14.73
         Canceled....................................        (277,579)      10.00 -   36.25          23.70
                                                          -----------     -----------------       --------
         Outstanding at December 31, 1997............       3,625,002       10.00 -   38.88          20.25
         Granted.....................................         708,086        5.56 -   26.75          21.11
         Exercised...................................          (3,675)      10.00 -   14.13          10.28
         Canceled....................................        (685,971)      10.00 -   38.88          29.60
                                                          -----------     -----------------       --------
         Outstanding at December 31, 1998............       3,643,442        5.56 -   34.75          18.79
                                                          -----------     -----------------       --------
         Granted.....................................       3,855,408        1.06 -    2.63           1.27
         Canceled....................................      (7,498,850)       1.06 -   34.75           9.78
                                                          -----------     -----------------       --------
         Outstanding at December 31, 1999............              --     $    --   $    --       $     --
                                                          ===========     =================       ========


</TABLE>

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).

         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:


<TABLE>
<CAPTION>
                                                                           PREDECESSOR COMPANY
                                                            --------------------------------------------------
                                                                 1999              1998               1997
                                                            ------------      ------------       -------------
<S>                                                         <C>               <C>                <C>
         Pro forma net income (loss) .................      $     97,883      $   (320,127)      $   (142,585)
                                                            ============      ============       ============
         Pro forma net income (loss) per share .......      $       3.95      $     (12.88)      $      (6.16)
                                                            ============      ============       ============


</TABLE>
         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:

<TABLE>
<CAPTION>
                                           1999           1998           1997
                                         --------       --------       --------
<S>                                           <C>            <C>            <C>
         Expected life (years) ....           2.4            4.5            4.5
         Interest rate ............          4.67%           5.5%          6.17%
         Volatility ...............          77.0%          52.9%          45.6%
         Dividend yield ...........            --             --             --


</TABLE>






                                      F-19
<PAGE>   53

                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



         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.


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):


<TABLE>
<CAPTION>
                                                                      PREDECESSOR COMPANY
                                                                FOR THE YEARS ENDED DECEMBER 31,
                               --------------------------------------------------------------------------------------------------
                                           1999                              1998                                1997
                               -----------------------------  ---------------------------------   -------------------------------
                                                      Per                                Per                               Per
                                Income    Shares     Share       Loss      Shares       Share       Loss       Shares     Share
                               ---------  -------  ---------  ---------    -------    ---------   ---------   --------  ---------
<S>                            <C>         <C>          <C>   <C>           <C>       <C>         <C>           <C>        <C>
BASIC EPS
     Income (loss) available
     To common stockholders    $ 109,852   24,754  $    4.44  $(314,494)    24,856    $  (12.65)  $(134,818)    23,142  $   (5.83)

EFFECT OF DILUTIVE SECURITIES
     Options & Warrants               --       --         --         --         --           (1)         --         --         (1)
                               ---------  -------  ---------  ---------    -------    ---------   ---------   --------  ---------

DILUTED EPS
     Income (loss) available
     To common stockholders
     And assumed exercises     $ 109,852   24,754  $    4.44  $(314,494)    24,856    $  (12.65)  $(134,818)    23,142  $   (5.83)
                               =========  =======  =========  =========    =======    =========   =========   ========  =========

</TABLE>

(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





                                      F-20
<PAGE>   54
                                  FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)




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.

         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:

<TABLE>
<CAPTION>
                                                                              Average
                                                    Volume in              NYMEX Contract
                                                  Bbl's Per Day             Price Per Bbl
                                                  -------------             -------------
<S>                                                   <C>                <C>
         January 2000 - March 2000                    2,000              $       21.85
         January 2000 - May 2000                      1,000                      21.56
         January 2000 - June 2000                     8,000                      19.28
         March 2000                                   5,000                      30.05
         April 2000 - May 2000                        7,000                      28.58
         April 2000 - June 1000                       2,000                      21.00
         June 2000                                    6,000                      27.02
         July 2000 - December 2000                   12,000                      24.86

</TABLE>

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

<TABLE>
<CAPTION>
                                               Volume in             Weighted Average
                                                  Mcf                 NYMEX Contract
                                                Per Day                Price Per Mcf
                                               --------              ---------------
<S>                                            <C>                   <C>
         January 2000                            40,000                $     3.04
         February 2000                           40,000                      2.87
         April 2000 - June 2000                 110,000                      2.63
         July 2000 - December 2000              100,000                      2.76


</TABLE>

         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-21
<PAGE>   55
                                 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:

                                                           (in thousands)
               2000.....................................     $   1,444
               2001.....................................         1,397
               2002.....................................         1,000
               2003.....................................           164
                                                             ---------
               Total....................................     $   4,005
                                                             =========

         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.



                                      F-22
<PAGE>   56
                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


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):

<TABLE>
<CAPTION>
                                                         PREDECESSOR COMPANY
                                            -------------------------------------------
                                              1999              1998             1997
                                            --------         ---------         --------
<S>                                         <C>              <C>               <C>
     Cornerstone Propane, Inc               $ 28,115         $  30,076         $ 93,342
     Torch Energy Corporation                 30,281            42,171               --
     Tesoro Company                           46,139                --               --
     H&N Gas Ltd                              47,227                --               --
     Texon Corporation                            --                --           20,360


</TABLE>

         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.

NOTE 14 -- CURRENT ASSETS AND LIABILITIES

         Current assets and liabilities include the following:

<TABLE>
<CAPTION>
                                                             Successor    |   Predecessor
                                                              Company     |     Company
                                                             December 31, |   December 31,
                                                                 1999     |      1998
                                                             ------------ |   ------------
<S>                                                            <C>        |   <C>
         CURRENT ASSETS:                                                  |
         Accounts receivable-joint interest billings ....      $  9,199   |   $  7,331
         Accrued oil and gas sales ......................        34,133   |     22,691
         Other ..........................................            --   |        411
         Allowance for doubtful accounts ................        (2,000)  |     (2,000)
                                                               --------   |   --------
              Accounts receivable, net ..................      $ 41,332   |   $ 28,433
                                                               ========   |   ========
                                                                          |
         Prepaid drilling cost ..........................      $  5,393   |   $  4,789
         Royalties and production taxes receivable ......         2,581   |      5,463
         Collateral deposit for hedging contracts .......         5,977   |         --
         Other ..........................................         4,911   |      9,416
                                                               --------   |   --------
              Other current assets ......................      $ 18,862   |   $ 19,668
                                                               ========   |   ========
         CURRENT LIABILITIES:                                             |
         Accounts payable................................      $ 58,917   |   $ 42,183
         Accrued drilling cost ..........................        11,693   |     25,725
         Accrued lease operating expenses ...............         6,146   |     12,828
         Accrued interest expense .......................        20,917   |     10,799
         Revenue and royalties payable ..................         5,779   |      4,588
         Accrued reorganization costs ...................        11,236   |         --
         Other ..........................................         6,240   |     10,897
                                                               --------   |   --------
              Accounts payable and                                        |
                accrued liabilities .....................      $120,928   |   $107,020
                                                               ========   |   ========

</TABLE>



                                      F-23
<PAGE>   57
                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)




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.


NOTE 16 --  SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)

                      (In thousands except per share data)

<TABLE>
<CAPTION>
                                                                Predecessor Company
                                        -------------------------------------------------------------------
1999                                      First        Second        Third         Fourth          Annual
----                                    ---------    ---------    ---------      ---------       ----------
<S>                                     <C>          <C>          <C>            <C>             <C>
Revenues............................    $  59,738    $  70,607    $  67,598      $   74,237      $  266,730
Income (loss) from operations.......    $  (3,357)   $  11,498    $  15,130      $   27,288      $   45,109
Net income (loss)...................    $ (10,251)   $   2,626    $   8,718      $  108,759(2)   $  109,852
Net income (loss) per share:
         Basic and Diluted..........    $    (.41)   $     .11    $     .35      $     4.39      $     4.44


1998
----
Revenues............................   $   71,955    $  70,778    $  67,898      $   62,918      $  273,549
Income (loss) from operations.......   $    6,984    $   2,783    $     186      $ (277,942)(1)  $ (267,989)
Net Loss............................   $   (1,599)   $  (5,611)   $ (12,577)     $ (294,707)     $ (314,494)
Net Loss:
         Basic and Diluted..........   $     (.06)   $    (.23)   $    (.51)     $   (11.92)     $   (12.65)


</TABLE>

(1)  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").

(2)  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).




                                      F-24
<PAGE>   58
                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


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):

<TABLE>
<CAPTION>
                                                                             Predecessor Company
                                                                   ---------------------------------------
                                                                      1999           1998          1997
                                                                   ---------      ----------    ----------
<S>                                                                     <C>           <C>           <C>
         Acquisition of properties:
              Proved properties....................                $       --     $   37,880    $  168,450
              Unevaluated properties...............                     1,234         17,430        41,907
         Exploration costs.........................                    27,475        158,331       176,543
         Development costs.........................                    47,836        111,546       106,260
                                                                   ----------     ----------    ----------
                  Total............................                $   76,545     $  325,187    $  493,160
                                                                   ==========     ==========    ==========

</TABLE>

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):

<TABLE>
<CAPTION>
                                                                       Successor    |          Predecessor
                                                                         Company    |            Company
                                                                        ----------  |   ---------------------------
                                                                          1999      |       1998            1997
                                                                        ----------  |   -----------     -----------
<S>                                                                     <C>         |   <C>             <C>
         Proved properties .......................................      $  450,000  |   $ 1,313,824     $   999,126
         Unevaluated properties ..................................          60,000  |       165,885         165,480
                                                                        ----------  |   -----------     -----------
                                                                        $  510,000  |   $ 1,479,709     $ 1,164,606
         Accumulated depletion, depreciation and amortization ....              --  |      (874,064)       (455,340)
                                                                        ----------  |   -----------     -----------
                  Total ..........................................      $  510,000  |   $   605,645     $   709,266
                                                                        ==========  |   ===========     ===========

</TABLE>

         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):

<TABLE>
<CAPTION>
                                                                                        PREDECESSOR COMPANY
                                                                                   FOR THE YEAR ENDED DECEMBER 31,
                                                                            -----------------------------------------
                                                                               1999            1998            1997
                                                                            ---------       ---------       ---------
<S>              <C>                                                        <C>             <C>             <C>
         Revenues(1) .................................................      $ 257,646       $ 256,655       $ 292,456
         Production costs ............................................        (91,521)       (103,460)        (81,965)
         Depreciation, depletion and amortization ....................       (114,064)       (145,856)       (113,347)
         Impairment of oil and gas properties ........................             --        (275,000)       (200,000)
         Income tax benefit (provision) ..............................             --              --          20,621
                                                                            ---------       ---------       ---------
         Results of operations for petroleum producing activities ....      $  52,061       $(267,661)      $ (82,235)
                                                                            =========       =========       =========
         Average realized sales prices(2):
         Liquids (per Bbl)(3) ........................................      $   15.48       $   12.54       $   17.34
         Natural gas (per Mcf) .......................................      $    2.27       $    2.16       $    2.41
</TABLE>


-----------

(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.


                                      F-25
<PAGE>   59
                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


RESERVE QUANTITIES (UNAUDITED)

         Estimates of proved reserves of the Company and the related
standardized measure of discounted future net cash flow information are based on
the reports of independent petroleum engineers. All of the Company's 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 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-26
<PAGE>   60
                                 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:


<TABLE>
<CAPTION>
                                                         LIQUIDS (1)      GAS
                                                          (MBbl)         (MMcf)
                                                         -------       --------
<S>                                                       <C>           <C>
1997
----
Proved developed and undeveloped:
Beginning of year .................................       54,659        256,913
Production ........................................       (8,210)       (57,737)
Purchases of minerals-in-place ....................       12,229         63,004
Extensions and discoveries ........................           48        110,270
Revisions to previous estimates ...................         (683)         8,311
                                                         -------       --------
End of year .......................................       58,043        380,761
                                                         =======       ========
Proved developed:
               Beginning of year ..................       45,040        187,949
                                                         =======       ========
               End of year ........................       39,766        309,542
                                                         =======       ========

1998
----
Proved developed and undeveloped:
Beginning of year .................................       58,043        380,761
Production ........................................       (8,513)       (76,799)
Purchases of minerals-in-place ....................        3,324         44,161
Extensions and discoveries ........................        3,204         47,088
Sales of minerals-in-place ........................         (118)        (6,080)
Revisions to previous estimates ...................       (6,551)       (19,188)
                                                         -------       --------
End of year .......................................       49,389        369,943
                                                         =======       ========
Proved developed:
               Beginning of year ..................       39,766        309,542
                                                         =======       ========
               End of year ........................       31,746        297,117
                                                         =======       ========

1999
----
Proved developed and undeveloped:
Beginning of year .................................       49,389        369,943
Production ........................................       (7,877)       (61,048)
Purchases of minerals-in-place ....................           --             --
Extensions and discoveries ........................        2,589          6,929
Sales of minerals-in-place ........................         (429)        (4,544)
Revisions to previous estimates ...................       21,287        (10,664)
                                                         -------       --------
End of year (Successor Company) ...................       64,959        300,616
                                                         =======       ========
Proved developed:
               Beginning of year ..................       31,746        297,117
                                                         =======       ========
               End of year (Successor Company) ....       41,650        243,119
                                                         =======       ========


</TABLE>

(1) Includes crude oil, condensate and natural gas liquids.

         Proved reserves are estimated quantities of liquids and natural gas
which geological and engineering data indicate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves, which can
be expected to be recovered through existing wells with existing equipment and
operating methods.

         Revisions to previous estimates for the year ended December 31, 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.




                                      F-27
<PAGE>   61
                                 FORCENERGY INC
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

         The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves is as follows (in thousands):

<TABLE>
<CAPTION>
                                                                                    Predecessor Company
                                                                     -----------------------------------------------
                                                                              For the Year Ended December 31,
                                                                     -----------------------------------------------
                                                                          1999             1998              1997
                                                                     -----------       -----------       -----------
<S>                                                                  <C>               <C>               <C>
Future cash inflows ...........................................      $ 2,158,260       $ 1,217,620       $ 1,683,235
Future production costs .......................................         (624,130)         (391,478)         (530,327)
Future development and dismantlement costs ....................         (326,129)         (280,155)         (311,065)
                                                                     -----------       -----------       -----------
Future net cash flows (pre-tax)................................        1,208,001           545,987           841,843
10% annual discount for estimated timing of cash flows ........         (349,671)         (109,298)         (205,424)
                                                                     -----------       -----------       -----------
Discounted future net cash flows (pre-tax).....................          858,330           436,689           636,419
Discounted future net income taxes.............................          (89,401)                0           (41,221)
                                                                     -----------       -----------       -----------
Standardized measure of discounted future net cash flows
   (after tax).................................................      $   768,929       $   436,689       $   595,198
                                                                     ===========       ===========       ===========

</TABLE>

         The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows (in thousands):

<TABLE>
<CAPTION>
                                                                                 Predecessor Company
                                                                     -----------------------------------------
                                                                           For the Year Ended December 31,
                                                                     -----------------------------------------
                                                                         1999            1998           1997
                                                                     ---------       ---------       ---------
<S>                                                                  <C>             <C>             <C>
Standardized measure -- beginning of period ...................      $ 436,689       $ 595,198       $ 802,145
Sales of oil and gas produced, net of production costs ........       (166,125)       (168,950)       (210,491)
Purchases of minerals-in-place ................................             --          19,066         160,608
Extensions and discoveries ....................................         64,600          72,228         144,126
Sales of minerals-in-place ....................................         (6,527)         (7,921)         (1,322)
Net changes in prices and production costs ....................        440,630        (156,301)       (575,863)
Changes in estimated future development and
   dismantlement costs ........................................        (30,974)        (13,327)        (21,217)
Revisions to previous quantity estimates ......................         41,586         (14,623)         11,087
Accretion of discount .........................................         43,669          59,520          80,215
Changes in timing of production and other .....................         34,782          10,578          (6,635)
Net changes in income taxes ...................................        (89,401)         41,221         212,545
                                                                     ---------       ---------       ---------
Standardized measure -- end of period .........................      $ 768,929       $ 436,689       $ 595,198
                                                                     =========       =========       =========


</TABLE>

         The standardized measure is based on current prices as of the valuation
date and reflects overall weighted average prices of:

<TABLE>
<CAPTION>
                                            Predecessor Company
                                  -------------------------------------
                                      For the Year Ended December 31,
                                  -------------------------------------
                                    1999          1998          1997
                                  --------      --------      ---------
<S>                               <C>           <C>           <C>
Oil (per Bbl) ..............      $  22.37      $  10.67      $  14.72
Gas (per Mcf) ..............      $   2.34      $   1.98      $   2.18

</TABLE>



                                      F-28