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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K/A
<TABLE>
<C> <S>
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ____________ TO____________
</TABLE>
COMMISSION FILE NUMBER: 0-26444
FORCENERGY INC.
(Exact Name of Registrant as Specified in Its Charter)
<TABLE>
<S> <C>
DELAWARE 65-0429338
(State or other jurisdiction of incorporation or (I.R.S. Employer Identification No.)
organization)
2730 S.W. 3RD AVENUE
SUITE 800
MIAMI, FLORIDA 33129-2356
(Address of principal executive offices) (Zip Code)
</TABLE>
Registrant's telephone number, including area code: (305) 856-8500
Securities Registered Pursuant to Section 12(b) of the Act:
NONE
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, PAR VALUE $.01 PER SHARE
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by checkmark if disclosure of delinquent filings pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE
PRECEDING FIVE YEARS:
Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Section 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court. Yes [X] No [ ]
On February 15, 2000, the Registrant's Chapter 11 plan became effective,
old shares of common stock were cancelled and new shares of common stock were
authorized and issued. As of March 28, 2000, the total number of outstanding
shares of new Common Stock is 24,000,000. The aggregate market value of the
voting and non-voting equity held by non-affiliates was estimated to be $113
million at March 29, 2000.
DOCUMENTS INCORPORATED BY REFERENCE:
Proxy statement of Forcenergy Inc relative to the Annual Meeting of
Shareholders on June 7, 2000 which is incorporated by reference into Part III of
this Form 10-K.
<PAGE> 2
FORM 10-K/A
FORCENERGY INC
TABLE OF CONTENTS
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PAGE
NUMBER
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<S> <C> <C>
PART I
Item 1. Business.................................................... 1
PART II
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 12
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 19
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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
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through a continuing program of further development through selective
exploitation and exploratory drilling and through the enhancement of production
through workovers and recompletions. Forcenergy emphasizes the use of 3-D
seismic and computer-aided exploration technology, together with geologic and
engineering studies of its properties, to evaluate and prioritize drilling
prospects. Focusing drilling activities on producing properties in the Gulf of
Mexico permits Forcenergy to utilize its base of geological, engineering and
production experience in the region to maximize its drilling success and to
minimize finding and development costs. Furthermore, Forcenergy's concentration
of drilling activities on its producing properties with existing infrastructure
results in the addition of new production with minimal incremental lease
operating expenses and minimal additional facility costs. Also avoided are
lengthy timing delays in commencing production.
Forcenergy prefers to operate its Gulf of Mexico properties because
functioning in that capacity positions it to more effectively manage production
performance and operating expenses and allows it to control the timing and
amount of capital expenditures. As of December 31, 1999, Forcenergy operated 119
structures and 440 wells in the Gulf of Mexico. Forcenergy believes that the
operating expertise and experience of its personnel have been instrumental in
its ability to enhance and improve production rates and cash flows. Of
particular importance, a significant portion of the drilling prospects
Forcenergy may pursue during the next three to five years are accessible from
existing production facilities operated by the Company.
Cook Inlet, Alaska. Since its discovery, oil and gas activities in the
Cook Inlet area have been dominated by major oil companies. These companies have
reduced their activity in the region over the past ten to twenty years as they
have refocused their Alaskan efforts on the North Slope (Prudhoe Bay) area.
Forcenergy's business strategy in the Cook Inlet area is to increase production
and cash flow through the exploitation of existing producing properties as well
as to expand its presence in the Cook Inlet area through selective exploration
on undeveloped leases. Forcenergy believes that it has assembled a high quality,
producing asset base with exploitation potential as well as the seventh largest
exploratory lease position in the State of Alaska, both of which will give
Forcenergy an opportunity to add significant new reserves through drilling. In
1998, Forcenergy completed the largest proprietary 3-D seismic survey in Cook
Inlet and since then has acquired additional 3-D seismic data to identify
additional drilling prospects. Forcenergy believes that its strategy will allow
it to economically exploit opportunities previously not pursued by the major oil
companies by utilizing proprietary 3-D seismic data, smaller, less capital
intensive offshore production facilities and other methods that have proven
successful in the Company's operations in the Gulf of Mexico. The Company
intends to pursue an active development and exploration program in the Cook
Inlet for at least the next two or three years.
International. Forcenergy's international business strategy has
historically been aimed at achieving significant reserve growth through
participation in selected high risk, high reward exploration prospects. Going
forward the Company will lower its risk by farming out exploratory projects to
industry partners while still maintaining a meaningful working interest
position. The Company also reviews international producing property acquisition
opportunities that might provide an operating base from which it could apply its
corporate strategy of finding and developing additional reserves on producing
properties through the use of advanced technologies. Forcenergy presently holds
exploratory acreage offshore Gabon, West Africa and onshore Australia.
TECHNOLOGY
Forcenergy utilizes advanced technology in its exploration and development
activities in order to reduce drilling risks and finding costs and to more
effectively prioritize drilling prospects based on return potential. The Company
currently has acquired 848 square miles of 3-D seismic surveys on 105 of its 175
offshore Gulf of Mexico lease blocks and 2,305 square miles on other Gulf of
Mexico blocks in which it currently does not own an interest. Forcenergy also
owns approximately 140,000 linear miles of high quality 2-D seismic data on Gulf
of Mexico blocks. Approximately 240 square miles of 3-D seismic data has been
acquired in the Cook Inlet, Alaska. Additionally, the Company has acquired 973
square miles of 3-D seismic on its exploratory Gryphon Marin concession in
Gabon, Africa. The use of the 3-D seismic data will enable the Company to
identify multiple development and exploratory prospects in mature producing
fields, which were not identified
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through earlier technologies. Forcenergy's professional staff includes 16
geoscientists experienced in interpreting 3-D data.
1999 AND 1998 DRILLING ACTIVITY
During the bankruptcy process in 1999, Forcenergy's capital program was
restricted by the Bankruptcy Court. Available capital was used primarily to
minimize production declines and maximize cash flow by targeting development and
lower-risk exploitation prospects. During 1999, Forcenergy spent $69.7 million
on its capital drilling and workover program, including $7.5 million in
capitalized internal costs and $6.1 million on undeveloped leasehold and seismic
costs.
Gulf of Mexico. The Company spent approximately $46.2 million for capital
drilling expenditures in the Gulf of Mexico during 1999. Three of three
development wells and four of six exploratory wells drilled proved successful.
The most significant activity centered around the exploitation and development
of producing properties. Two exploratory wells and one development well were
successfully drilled at the Vermilion 380 field (100% working interest). These
wells commenced production in October 1999 at an average rate of 1,200 barrels
of oil equivalent per day and added an estimated 1,534 MBOE to the proved
reserve base during 1999. Forcenergy spent approximately $150.2 million for
capital drilling expenditures in the Gulf of Mexico during 1998 adding
approximately 19,725 barrels equivalent of production per day and added
approximately 9.6 million barrels equivalent to the proved reserve base in 1998.
Three of four development wells and thirteen of twenty exploratory wells drilled
proved successful. Three successful exploratory wells were drilled at the High
Island A-552 field (100% working interest). One development well and three
exploratory wells in the Mississippi Canyon 148 field (28.5% working interest)
were successfully completed. Additionally, four exploratory wells were
successfully completed in the West Cameron 630 field (100% working interest). In
the South Timbalier 148 field (15.5% working interest), one development well and
one exploratory well were successfully completed.
Cook Inlet, Alaska. The Company's major priority in Alaska in 1999 was to
resume the construction of the Osprey Platform for the Redoubt Shoal prospect.
The Company anticipates that the platform will be set by the third quarter of
2000 and drilling will commence during the fourth quarter. During 1998,
Forcenergy completed a successful development well in the 100% owned West
McArthur River Field that increased field production by approximately 1,950
BOPD, net to the Company, and added 1,500 MBOE to the proved reserve base by
extending the field boundaries. Also during 1998, the Company spent
approximately $10.9 million on 3-D seismic data to better delineate the West
McArthur River Field and the Redoubt Shoal prospect, and incurred approximately
$15.1 million on the construction of the drilling platform and facilities for
the Redoubt Shoal prospect.
Onshore Properties. Approximately $6.1 million in total capital was spent
on onshore properties during 1999. The majority of these expenditures were spent
on recompletions and workovers of wells in existing producing fields.
Approximately $39.4 million in total capital was spent during 1998, $10.7
million of which was incurred on unproved leases primarily in east Texas, and
$9.1 million for the acquisition of producing properties in southeastern New
Mexico and Texas.
International. In December 1997 and January 1998, the Company drilled two
exploratory dry holes on its Phenix Marin concession located offshore Gabon,
West Africa. Additional exploratory opportunities in deeper waters have been
identified within the Phenix Marin concession. Forcenergy has acquired a
large-scale proprietary 3-D seismic survey over the southern portion of the
offshore Gryphon Marin concession that is north of the Phenix Marin concession.
Forcenergy believes that numerous drilling opportunities will be generated from
the information obtained through this 3-D survey. The Company also believes that
there is potential in the northern portion of the Gryphon Marin concession where
a recent discovery approximately 5-7 miles from Forcenergy's concession was
announced. The Company is currently reviewing various farmout opportunities for
both concessions.
In Australia, the Company drilled or reentered 11 wells during 1998 and
early 1999 on its 2.4 million acre PEL 238 concession in New South Wales, a coal
bed methane gas prospect. Dewatering of these wells continues, however, they
have not produced at commercial rates. Forcenergy plans to drill at least 3
additional
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wells on the PEL 238 concession to further evaluate a conventional gas play and
to fulfill the remaining earning requirements of the concession.
ADDITIONAL FUTURE PROJECTS
Forcenergy's reduced drilling activity during the bankruptcy process
allowed it to focus the attention of its technical personnel on data previously
acquired for the purpose of generating additional new prospects on its existing
properties. As a result of that effort, Forcenergy has identified a substantial
inventory of more exploitation, development, exploratory, workover and
recompletion projects on its existing Gulf of Mexico and Alaska properties which
could be undertaken over the next three to five years. Many of these projects
are currently being reviewed by Forcenergy's geoscientists utilizing 3-D seismic
data acquired in the last three years.
The Company's budget for fiscal 2000 provides for $142 million in capital
expenditures including $13.5 million in capitalized internal costs. The Company
expects to spend approximately $79 million, $48 million and $13 million in the
Gulf of Mexico, Alaska and Onshore, respectively, and approximately $2.0 million
internationally.
GULF OF MEXICO PROPERTIES
Forcenergy currently holds working interests in 210 federal offshore and
state lease blocks located in the Gulf of Mexico and Gulf Coast, including a
100% working interest in 60 of these blocks and a 50% or greater working
interest in 26 other blocks, and operates 58 of the producing blocks
representing 70% of its current Gulf of Mexico/Gulf Coast production. The
following table lists the average working interest, net proved reserves and the
operator for Forcenergy's nineteen largest offshore Gulf of Mexico properties,
comprising approximately 79% of Forcenergy's net proved reserves in the Gulf of
Mexico and 41% of Forcenergy's total net proved reserves, as of December 31,
1999:
<TABLE>
<CAPTION>
ESTIMATED NET PROVED RESERVES AT
DECEMBER 31, 1999
AVERAGE ----------------------------------
WORKING OIL NATURAL GAS TOTAL
INTEREST (MBbls) (MMcf) (MBOE) 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
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the operated West McArthur River Field located in the Cook Inlet purchased from
Stewart Petroleum Company in June 1997. These fields had estimated net proved
reserves of 28.1 million barrels of oil and comprised approximately 24% of
Forcenergy's total estimated net proved reserves at December 31, 1999.
Through lease sales, the Marathon and Stewart acquisitions and several
other smaller property acquisitions, Forcenergy has assembled the seventh
largest exploratory lease acreage position in the State of Alaska.
ONSHORE PROPERTIES
Forcenergy owns working and royalty interests in approximately 1,990
producing oil and gas wells in 882 fields in the Rocky Mountain, Gulf Coast,
Permian Basin and Appalachian regions of the United States. Management believes
that Forcenergy's stable reserve base of long-lived, primarily non-operated,
onshore properties complements the Gulf of Mexico and Alaska operations by
providing an additional source of cash flow that requires limited management
involvement. Forcenergy's onshore properties accounted for approximately 24% of
estimated net proved reserves at December 31, 1999.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, the Company makes only
a cursory review of title to farmout acreage and to onshore undeveloped oil and
natural gas leases upon execution of the contracts. Prior to the commencement of
drilling operations, a thorough title examination is conducted and curative work
is performed with respect to significant defects. The Company performs complete
reviews of title to federal and state offshore lease blocks prior to
acquisition. To the extent title opinions or other investigations reflect
material title defects, the seller of the property, rather than the Company, is
typically responsible for curing any such title defects at its expense. If the
Company were unable to remedy or cure any title defect of a nature such that it
would not be prudent to commence drilling operations on undeveloped properties,
the Company could suffer a loss of its entire investment in the leasehold. The
Company has obtained title opinions on substantially all of its producing
properties and believes that it has satisfactory title to such properties in
accordance with standards generally accepted in the oil and gas industry.
Approximately 95% of the Company's proven oil and natural gas reserves are
mortgaged to secure borrowings under the Company's current senior credit
facility (see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources").
CEILING LIMITATION WRITEDOWNS
The Company reports its operations using the full cost method of accounting
for oil and gas properties. Under the full cost accounting rules, the net
capitalized costs of oil and gas properties may not exceed a "ceiling limit",
calculated at the end of each quarter, which is based upon the present value of
estimated future net cash flows from proved reserves using period end prices and
costs, discounted at 10%, plus the lower of cost or fair market value of
unproved properties, net of related tax effects. If net capitalized costs of oil
and gas properties exceed the ceiling limit, the Company is subject to a ceiling
limitation writedown to the extent of such excess. A ceiling limitation
writedown is a charge to earnings which does not impact cash flows. However,
such writedowns permanently impact the amount of the Company's stockholders'
equity. The risk that the Company will be required to write down the carrying
value of its oil and gas properties increases when oil and gas prices are
depressed or volatile. Application of these rules during periods of relatively
low oil or gas prices, even if temporary, may result in a ceiling writedown. In
addition, writedowns may occur if the Company has substantial downward revisions
in its estimated proved reserves or adds significant costs to the full cost pool
without adding significant value to its reserve base. Higher operating costs and
lower price realizations on production in Alaska make the Company's Alaska
reserves more sensitive to price changes and potential writedowns than reserves
in the Gulf of Mexico. Under the full cost accounting rules the Company's
reserves exceeded the recorded cost at December 31, 1999. However, based on
prices being received as of December 31, 1998 and 1997, the Company recorded
non-cash impairments in the fourth quarters ended December 31, 1998 and 1997 of
$275 million and $200 million ($162.8 million after tax), respectively, pursuant
to full cost accounting rules. Although oil and gas prices are currently higher
than those at year end
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1999, if prices decreased significantly, the Company's capitalized costs could
again exceed the present values of estimated future net revenue. If these
capital costs were not offset by other factors, they could result in additional
writedowns of Forcenergy's oil and gas properties. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
ABANDONMENT COSTS
Forcenergy is responsible for the costs associated with the plugging of
wells, the removal of facilities and equipment and site restoration on its oil
and gas properties, pro rata to its working interest. The Company provides for
expected future abandonment liabilities by accruing for such costs as a
component of depletion, depreciation and amortization as production occurs. The
Company also accounts for these future liabilities by including all projected
abandonment costs as a reduction in the future cash flows from its reserves in
its reserve reporting. As of December 31, 1999, total undiscounted abandonment
costs estimated to be incurred were approximately $144.8 million for properties
in offshore Gulf of Mexico and Alaska waters. For onshore properties, salvage
values received for equipment are usually sufficient to offset the abandonment
costs. Estimates of abandonment costs and their timing may change due to many
factors, including actual drilling and production results, inflation rates,
changes in abandonment techniques and technology and changes in environmental
laws and regulations. Approximately $6.4 million in abandonment costs are
anticipated to be incurred in 2000, all of which will be funded by cash flow
from operations or from temporary borrowings.
The Minerals Management Service ("MMS") requires operators of Outer
Continental Shelf ("OCS") properties to post performance bonds in connection
with the plugging and abandonment of wells located offshore and the removal of
all production facilities. Operators in the OCS waters of the Gulf of Mexico are
also currently required to post an area wide bond for the lesser of $3 million
or $500,000 per producing lease. The MMS may also require that operators provide
supplemental bonding on a property-by-property basis to insure that funds will
be available to properly plug and abandon the wells and facilities once the
fields are depleted. The Company currently provides approximately $80 million in
supplemental bonding on its operated offshore leases as required by the MMS.
Under certain circumstances, the MMS has the authority to suspend or terminate
operations on federal leases for failure to comply with applicable bonding
requirements or other regulations applicable to plugging and abandonment. Any
such suspensions or terminations of the Company's operations could have a
material adverse effect on the Company's financial condition and results of
operations. To the best of its knowledge, the Company is currently in compliance
with all MMS requirements.
COMPETITION
Forcenergy encounters competition from other oil and gas companies in all
phases of its operations, including the acquisition of producing properties.
Competitors include major integrated oil and natural gas companies, numerous
independent oil and natural gas companies, individuals and drilling and income
programs. Many competitors are large, well-established companies with
substantially larger operating staffs and greater capital resources than the
Company's and which, in many instances, have been engaged in the energy business
for a much longer time. Such companies may be able to pay more for productive
oil and natural gas properties and exploratory prospects and to define,
evaluate, bid for and purchase a greater number of properties and prospects than
the Company's financial or human resources permit. Forcenergy's ability to
acquire additional properties and to discover reserves in the future will be
dependent upon its ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
MARKETING AND CUSTOMERS
Forcenergy sells substantially all of its natural gas under short-term
contracts (maximum of one year in duration) at pricing based on current spot
market indexes. A minor portion of the Company's gas production is committed to
be processed through gas plants. Crude oil and condensate from Gulf of Mexico
and onshore properties is typically sold at the wellhead under short-term
contracts at posted market-based field prices.
Most of the Company's production is transported through gas gathering
systems and oil and gas pipelines that are not owned by the Company.
Transportation space on such gathering systems and pipelines is
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occasionally limited and at times unavailable due to repairs or improvements
being made to such facilities or due to such space being utilized by other
companies with priority transportation agreements. Forcenergy's access to
transportation options can also be affected by regulation of intrastate and
interstate gas transportation. In an attempt to promote competition, the Federal
Energy Regulatory Commission ("FERC") has issued a series of orders which have
altered significantly the marketing and transportation of natural gas, see
"Government Regulation". The effect of these orders to date has been to enable
producers such as the Company to market their natural gas production to
purchasers other than the interstate pipelines located in the vicinity of their
producing properties. While the Company has not experienced any inability to
market its production, if transportation space is restricted or is unavailable,
the Company's cash flow could be adversely affected.
During 1999, several purchasers of the Company's production individually
accounted for more than 10% of the value of oil and gas sold by the Company as
follows:
<TABLE>
<CAPTION>
PERCENT OF
REVENUES
----------
<S> <C>
Cornerstone Propane, Inc. ....................... 10.5%
Torch Energy Corporation......................... 11.4%
Tesoro Company................................... 17.3%
H&N Gas Ltd. .................................... 17.7%
</TABLE>
Based on current demand for oil and natural gas sold, the Company does not
believe the loss of these purchasers would have a material adverse effect on the
Company's results of operations or cash flow. The Company currently relies on
one purchaser for its Alaska production. The contract with this purchaser runs
through December 2000 at which time that contract must be extended or
renegotiated or another purchaser found. The net price provided for under this
contract is at a slight discount to the West Texas Intermediate price as quoted
on the New York Mercantile Exchange ("NYMEX"), after allowance for
transportation costs. The inability to negotiate a new contract or to find a new
purchaser could materially impact the Company's results of operations and cash
flows. (See Note 13 to the Company's Financial Statements).
The Company utilizes, from time to time, various financial instruments to
hedge portions of its current oil and gas production to achieve more predictable
cash flows and to reduce its exposure to fluctuations in oil and gas prices. The
remaining portion of current production is not hedged so as to provide the
Company the opportunity to benefit from increases in prices on that portion of
the production, should price increases materialize. See Note 10 to the Company's
Financial Statements and "Management's Discussion and Analysis of Financial
Condition and Results of Operations".
OPERATING RISKS OF OIL AND GAS OPERATIONS
The oil and gas business involves certain operating hazards such as well
blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pollution, releases of
toxic gas and other environmental hazards and risks, any of which could result
in substantial losses to the Company through the loss of hydrocarbons, pollution
claims, personal injury suits and damage to properties of the Company and
others. The Company's offshore operations also are subject to the additional
hazards of marine operations, such as severe weather, capsizing and collision
that can cause substantial damage to facilities, and possible business
interruption. The availability of a ready market for the Company's oil and
natural gas production also depends on the proximity of reserves to, and the
capacity of, oil and gas gathering systems, pipelines and trucking or terminal
facilities. Additionally, the Company may be liable for environmental damages
caused by previous owners of property purchased or leased by the Company. As a
result, substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce or eliminate the funds available for
drilling or acquisitions, or result in the loss of the Company's properties. In
accordance with customary industry practices, Forcenergy maintains insurance
against some, but not all, of such risks and losses. The Company does not carry
business interruption insurance. The occurrence of an event not fully covered by
insurance could have a material adverse effect on the financial condition,
results of operations and cash flow of the Company.
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<PAGE> 11
ENVIRONMENTAL MATTERS
The Company, as an owner or lessee and operator of oil and gas properties,
is subject to federal, state and local laws and regulations governing the
discharge of materials into, and the protection of, the environment. These laws
and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit drilling activities on certain
lands lying within wilderness, wetlands and other protected areas, and impose
substantial liabilities for pollution resulting from the Company's operations.
Stricter standards in environmental legislation may be imposed in the oil and
gas industry in the future, such as proposals made in Congress and at the state
level from time to time that would reclassify certain oil and natural gas
exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent and costly handling, disposal and
clean-up requirements. The impact of any such changes, however, would not likely
be any more burdensome to the Company than to any other similarly situated
company involved in oil and gas exploration and production.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to be responsible for the release of a hazardous substance
into the environment. These persons include the current owner and operator of
the site or sites where the release occurred, the owner and operator at the time
the release occurred, and companies that disposed or arranged for disposal of
the hazardous substances found at the site. Under CERCLA, such persons may be
subject to joint and several liabilities for the costs of cleaning up the
hazardous substances, for damages to natural resources, and for the costs of
certain health studies. Furthermore, it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by hazardous substances or other pollutants
released into the environment. Although the Company is not aware of any
circumstances which would give rise to CERCLA liability, it has not eliminated
the possibility that past releases have occurred on property now owned and
operated by the Company. The discovery of such past releases could cause the
Company to incur material costs under CERCLA.
The Oil Pollution Act of 1990 and regulations promulgated pursuant thereto
("OPA") impose a variety of obligations on "responsible parties" with respect to
the prevention of oil spills and liability for damages resulting from such
spills. A responsible party includes the owner or operator of a facility or
vessel that could be the source of an oil spill. For offshore facilities, the
responsible party is the lessee or permittee or holder of a right of use and
easement (granted under applicable state law or the Outer Continental Shelf
Lands Act "OCSLA") of the area in which the offshore facility is located. OPA
assigns liability to each responsible party for oil removal costs and a variety
of public and private damages, including natural resource damages. While
liability limits apply in some circumstances, a responsible party for an OCS
facility must pay all spill removal costs incurred by a federal, state or local
government. OPA establishes a liability limit (subject to adjustment annually
based on changes in the Consumer Price Index) for offshore facilities of all
removal costs plus $75,000,000. A party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction, or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Few defenses exist to the
liability imposed by OPA.
OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover a substantial portion of
environmental clean-up and restoration costs that could be incurred by
governmental entities in connection with an oil spill. Other requirements
imposed by OPA include the preparation of an oil spill contingency plan. A
failure to comply with ongoing requirements or inadequate cooperation in a spill
event may subject a responsible party to civil or criminal enforcement action.
In short, OPA places a burden on offshore lease holders to conduct safe
operations and take other measures to prevent oil spills; if one occurs, OPA
then imposes liability for resulting damages.
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures. Violations of environmental-related lease
conditions or
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<PAGE> 12
regulations issued pursuant to the OCSLA can result in substantial civil and
criminal penalties as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental prosecution or citizen initiated legal actions.
The Company maintains insurance coverages, which it believes are customary
in the industry, although it is not fully insured against many environmental
risks. Although the Company has not experienced any material adverse effect from
compliance with environmental requirements, nor is it aware of any material
environmental claims existing at December 31, 1999, there is no assurance that
material costs relating to environmental matters will not be incurred in the
future.
GOVERNMENT REGULATION
Forcenergy's drilling, production, transportation and marketing operations
are subject to various types of regulation at the federal, state and local
levels. Such regulation includes requiring permits for the drilling of wells,
maintaining bonding requirements in order to drill or operate wells, and
regulating the location of wells, the surface use and restoration of properties
upon which wells are drilling and the plugging and abandonment of wells.
Regulations also can limit production rates, require capital for environmental
compliance and affect the transportation and marketing of hydrocarbons.
Certain operations the Company conducts are on federal oil and gas leases,
which the MMS administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA (which
are subject to change by the MMS). For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, Army Corps of Engineers and Environmental
Protection Agency), lessees must obtain a permit from the MMS prior to the
commencement of drilling.
The MMS recently issued two final rules amending its regulations governing
the valuation, for royalty purposes, of natural gas produced from Indian leases
and oil produced from federal lands. With regard to the amended regulations
concerning Indian leases, which became effective January 1, 2000, the MMS added
alternative valuation methods to ensure that Indian lessors receive maximum
revenues from their mineral resources. In the second final rule, which becomes
effective June 1, 2000, the MMS is amending the regulations governing the
valuation of crude oil produced from Federal leases. The amendments addressing
federal leases include, inter alia: (1) changes to the valuation of oil that is
not sold pursuant to an arm's-length contract; (2) optional methods for valuing
crude oil production where it is sold at arm's-length following one or more
arm's-length exchanges or one or more transfers between affiliates; (3) changes
to the method of calculating actual transportation costs; (4) changes to the
definition of "affiliate" due to recent judicial opinions; (5) clarification
that the MMS will issue binding value determinations; and (6) additional
regulatory language clarifying that the MMS will not "second-guess" the value of
the oil subject to a sale under an arm's-length contract, unless the MMS finds
that a seller acted unreasonably or in bad-faith in the sale of oil from a
lease.
Additionally, the MMS is currently conducting a rulemaking concerning the
valuation, for royalty purposes, of oil produced from Indian lands. The Company
does not expect to experience any adverse material effect as a result of the
changes implemented by the final rules or the changes that could result from the
ongoing rulemaking, although the full impact of the amendments to the MMS'
valuation methodology on the Company's performance cannot be determined at this
time.
The interstate transportation and sale for resale of natural gas are
regulated by the Federal Energy Regulatory Commission ("FERC"). Commencing in
1985 and continuing with the issuance of Order No. 636 in 1992, the FERC
promulgated a series of orders and regulations that significantly fostered
competition in the business of transporting and marketing natural gas. These
orders and regulations induced, and ultimately required, interstate pipeline
companies to provide nondiscriminatory transportation services to producers,
marketers, and other shippers, regardless of whether those shippers were
affiliated with an interstate pipeline company. The FERC's initiatives have led
to the development of a competitive, unregulated, open access
9
<PAGE> 13
market for natural gas purchases and sales that permits all purchasers of
natural gas to buy gas directly from third-party sellers other than the
pipelines.
On February 9, 2000, the FERC issued Order No. 637, which permits, and in
some cases, requires, interstate natural gas pipelines to make certain changes
to the nature of interstate transportation services. The changes permitted or
required by Order No. 637 attempt to continue the development of competitive
natural gas markets under the open access regime created by Order No. 636. These
changes include, inter alia: (1) elimination, for a two-year period, of the rate
cap that applies to sales of released firm transportation capacity by pipelines'
firm shippers; (2) the adoption by pipelines of seasonal or term-differentiated
rates; (3) revisions to pipeline scheduling procedures that are designed to
place capacity released by firm shippers on a more equal footing with capacity
sales by pipelines; and (4) additional reporting requirements that seek to
increase the ability of the FERC and interested parties to monitor the actions
of pipelines and firm capacity holders and detect attempts to exercise market
power or to engage in unduly discriminatory conduct. The Company does not expect
to experience any adverse material effect as a result of these changes, although
the full impact of Order No. 637 on the Company's performance cannot be
determined at this time.
The FERC also has the authority, under the Interstate Commerce Act ("ICA"),
to regulate the rates and service conditions for the interstate transportation
of crude oil, liquids and condensate by common carrier pipelines. The ICA
requires that the rates charged by interstate common carriers, such as Cook
Inlet Pipeline Company, be just and reasonable and nondiscriminatory. On January
1, 1995, the FERC adopted regulations that established an indexing system for
petroleum pipeline transportation rates that permits petroleum pipelines to
change their rates within prescribed ceiling levels that are tied to the
Producer Price Index for Finished Goods. Rate increases made pursuant to the
index are subject to protest, but such protests must show that the portion of
the rate increase resulting from application of the index is substantially in
excess of the pipeline's increase in costs. If, upon completion of an
investigation, the FERC finds that a proposed new or changed rate is unlawful,
it is authorized to require the carrier to refund the revenues collected in
excess of those that would have been collected under a just and reasonable and
nondiscriminatory rate. Upon an appropriate showing, a shipper may obtain
reparations for damages sustained for a period of up to two years prior to the
filing of the complaint. In addition, Cook Inlet Pipeline Company is subject to
regulation by the Alaska Public Utilities Commission with respect to any
intrastate transportation provided by Cook Inlet Pipeline Company.
In addition, all pipeline operations on or across the outer continental
shelf are regulated under the OCSLA. Under the FERC's current regulatory regime,
transmission services must be provided on an open-access, non-discriminatory
basis, while gathering services are treated as non-jurisdictional activities not
subject to the FERC's jurisdiction. In 1996, the FERC issued a Statement of
Policy regarding its jurisdiction under the Natural Gas Act ("NGA") and OCSLA
over new natural gas facilities and services on the OCS. Generally, the FERC
retained its existing tests for determining the jurisdictional status of
offshore facilities, but eased the application of its jurisdiction over
facilities in water depths of 100-meters or more. Legislation and regulations
affecting the oil and gas industry are under constant review for amendment or
expansion by Congress, the FERC, state regulatory bodies and the courts. The
Company cannot predict when or if any such proposals might become effective, or
their effect, if any, on the Company's operations. The natural gas industry
historically has been very heavily regulated; therefore, there is no assurance
that the less stringent regulatory approach recently pursued by the FERC and
Congress will continue indefinitely into the future. The regulatory burden on
the oil and natural gas industry increases the Company's cost of doing business
and, consequently, affects its profitability and cash flow. In as much as such
laws and regulations are frequently expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
regulations.
OFFICES
Forcenergy currently leases approximately 12,600 square feet of office
space in Miami, Florida, where its principal offices are located, approximately
44,000 square feet in Metairie, Louisiana, approximately 8,500 square feet in
Anchorage, Alaska, and approximately 851 square feet in Lafayette, Louisiana.
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<PAGE> 14
EMPLOYEES
As of February 28, 2000, Forcenergy had 258 full time employees, 22 of whom
are located at the Company's corporate headquarters in Miami, Florida and 87 of
whom are located at the Company's operational headquarters in Metairie,
Louisiana and in its regional offices in Lafayette and Intracoastal City,
Louisiana, and Anchorage, Alaska. One hundred and thirty seven employees work
offshore in the Gulf of Mexico and 12 work in other field locations. None of
Forcenergy's employees are represented by a labor union and the Company does not
anticipate difficulty in labor relations.
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<PAGE> 15
PART II
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the
Company's historical financial position and results of operations for each of
the three years ended December 31, 1999 and should be read in conjunction with
the financial statements of the Company appearing elsewhere in this report. For
the period from March 21, 1999 to February 15, 2000 the Company operated as a
debtor-in-possession. Effective December 31, 1999 the Company adopted fresh
start reporting; accordingly the following results of operations express those
of the predecessor company.
RESULTS OF OPERATIONS
Operations
The following table sets forth the Company's historical operations data
during the periods indicated:
<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.
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).
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<PAGE> 16
Operating Income/Loss. For the year ended December 31, 1999, operating
income rose to $45.1 million compared to a $268.0 million operating loss
recorded for 1998. The increase in operating income is mainly due to a decrease
in lease operating expenses in 1999, lower depletion, depreciation and
amortization expense associated with lower production volumes in 1999 and the
fact that 1998 included a $275.0 million non-cash impairment recorded in the
fourth quarter of 1998 pursuant to full cost accounting rules mandated by the
Securities and Exchange Commission.
Production. The Company's net liquids production was 7,877 MBbls in 1999
compared to 8,513 MBbls in 1998. Net gas production was 61,048 MMcf for the year
ended December 31, 1999 compared to 76,799 MMcf produced in 1998. Production of
both liquids and gas production declined as the Company significantly reduced
its capital expenditure program beginning in the third quarter of 1998 because
of a lack of available capital, thereby limiting the Company's ability to
maintain production rates and to replace reserves produced. The reduction in
capital spending continued throughout 1999 while the Company operated under
bankruptcy court orders.
Revenues. Revenues were $266.7 million for the year ended December 31,
1999, compared to $273.5 million reported last year, as higher net realized
prices only partially offset lower production volumes. Average net realized
liquid prices rose to $15.48 per Bbl in 1999, a 24% increase compared with
$12.54 per Bbl received in 1998. Average net realized gas prices increased to
$2.27 per Mcf in 1999, a 5% increase compared with $2.16 per Mcf reported in the
prior year.
Average prices received for field production for 1999 were $16.12 per Bbl
and $2.14 per Mcf for liquids and natural gas, respectively. After taking into
account the effects of 1999 hedging activities entered into in order to
guarantee a certain level of cash flow from production (excluding the $5.5
million settlement on the cancellation of hedging contracts by the
counterparties subsequent to the Company's filing of Chapter 11), specifically a
$5.0 million decrease in liquids revenue and a $7.7 million increase in gas
revenue, net realized liquids prices were reduced to $15.48 per Bbl and natural
gas prices increased to $2.27 per Mcf. Average field prices for 1998 were $11.59
per Bbl and $2.06 per Mcf for liquids and natural gas, respectively. After
taking into account the effects of 1998 hedging activities, specifically an $8.0
million increase in liquids revenue and a $7.7 million increase in gas revenue,
net realized prices rose to $12.54 per Bbl and $2.16 per Mcf for liquids and
natural gas, respectively.
Lease Operating Expenses. Lease operating expenses were $87.0 million in
1999 compared to $99.2 million in 1998. The decrease related primarily to a
reduction in the Company's workover program because of capital constraints
during the bankruptcy process. On an equivalent unit of production basis, lease
operating expenses increased to $4.82 per BOE in 1999 from $4.66 per BOE in
1998, because of the decline in production volumes.
Depletion, Depreciation and Amortization ("DD&A"). DD&A expense declined
to $116.4 million in 1999 from $145.9 million for 1998. The decrease was
principally attributable to lower production volumes and a decrease in the DD&A
rate per unit of production from $6.84 per BOE in 1998 to $6.45 per BOE in 1999.
In addition, the Company recorded a non-cash impairment of oil and gas assets in
the fourth quarter of 1998 of $275 million.
General and Administrative Expense. General and administrative expenses,
net of overhead reimbursements and capitalized internal costs, were $13.7
million in 1999 compared with $17.2 million in 1998. General and administrative
expenses decreased primarily due to the closing of the Company's Houston office
in late 1998 and a company-wide reduction in staffing in the first quarter of
1999. On a per BOE-produced basis, general and administrative expenses decreased
to $.76 per BOE for 1999 compared with the $.81 per BOE reported for the 1998
year, despite the decrease in production volumes.
Other Income. Interest and other income increased to $7.0 million in 1999
from $1.6 million in 1998. The increase was primarily attributable to the $5.5
gain recorded on the Company's sale of Forcenergy AB, an inactive Swedish
subsidiary.
Interest Expense. Interest expense, net of amounts capitalized, decreased
to $32.3 million in 1999, compared to the $48.1 million incurred in 1998. The
Company discontinued the accrual of interest on the
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<PAGE> 17
senior subordinated note issues after the Chapter 11 filing on March 21, 1999.
This decrease in interest expense was partially offset by increased interest
expense on higher average outstanding principal balances under the Old Senior
Credit Facility in 1999 and the discontinuance of the capitalization of interest
expense on unproved projects in June, 1999. Capitalization of interest expense
on unproved properties was discontinued in connection with the cessation of
development activities associated with these properties during the pendency of
bankruptcy proceedings and because of the uncertainty as to whether, or when
these properties would be developed.
Reorganization Items. The Company recorded a net charge for reorganization
items of $69.9 million during 1999 in connection with its reorganization under
Chapter 11. Included in reorganization items for 1999 were legal and advisory
fees amounting to $5.1 million, bank and other administrative fees amounting to
$11.1 million and a charge of $56.0 million to restate the Company's assets to
fair market value under the "fresh-start reporting rules" for companies emerging
from bankruptcy (See Notes 1, 2 and 6 to the Consolidated Financial Statements
included elsewhere in this Form 10-K), partially offset by interest income of
$2.3 million associated with higher cash balances.
Extraordinary Item. The Company recorded a $160.0 million extraordinary
gain on the discharge of indebtedness in 1999 for the difference between the
face value of the Company's 8 1/2% Senior Subordinated Notes and 9 1/2% Senior
Subordinated Notes and unsecured trade accounts payable exchanged for new equity
in the Company and the fair market value of that new equity under the Plan of
Reorganization.
Comparison of the Years Ended December 31, 1998 and December 31, 1997
Operating and Net Income/Loss. The Company reported an operating loss of
$268.0 million for the year ended December 31, 1998, compared to the $126.4
million operating loss recorded for the prior year. Net loss for 1998 was $314.5
million compared to a net loss of $134.8 million in 1997. The decrease in
operating income and net income is mainly attributable to lower oil and gas
prices, incremental lease operating expenses from new properties acquired,
higher depletion, depreciation and amortization associated with higher
production volumes, a larger non-cash impairment of oil and gas assets recorded
in 1998 pursuant to full cost accounting rules mandated by the Commission and
higher interest expense, all of which are discussed below. Excluding the
impairment provisions, operating income for 1998 and 1997 would have been $7.0
million and $73.6 million respectively.
Production. The Company's net liquids production rose to 8,513 MBbls in
1998 from 8,210 MBbls in 1997, a 4% improvement. Net gas production increased to
76,799 MMcf for the year ended December 31, 1998, a 33% increase over the 57,737
MMcf produced in 1997. On an equivalent unit basis, 1998 production increased to
21,313 MBOE, 20% more than the 17,833 MBOE produced during 1997. The increase in
equivalent production resulted from producing properties in the Gulf of Mexico
acquired late 1997 and early 1998 and from the success of the Company's late
1997 and 1998 drilling and workover programs.
Revenues. Revenues were $273.5 million for the year ended December 31,
1998, compared to $284.2 million reported last year, as lower net realized
prices only partially offset by higher production volumes. Average net realized
liquid prices declined to $12.54 per Bbl in 1998, a 28% decrease compared with
$17.34 per Bbl received in 1997. Average net realized gas prices declined to
$2.16 per Mcf in 1998, a 10% decrease compared with $2.41 per Mcf reported in
1997.
Average prices received for field production for 1998 were $11.59 per Bbl
and $2.06 per Mcf for liquids and natural gas, respectively. After taking into
account the effects of 1998 hedging activities entered into in order to
guarantee a certain level of cash flow from production, specifically an $8.0
million increase in liquids revenue and a $7.7 million increase in gas revenue,
net realized prices were $12.54 per Bbl and $2.16 per Mcf for liquids and
natural gas, respectively. All commodity price hedging contracts in place were
cancelled at the option of the counterparty pursuant to the filing under Chapter
11 of the U.S. Bankruptcy Code on March 21, 1999. The aggregate fair market
value of the cancelled contracts, approximately $5.5 million, was remitted to
the Company in April 1999. Average field prices for 1997 were $17.70 per Bbl and
$2.55 per Mcf for liquids and natural gas respectively. After taking into
account the effects of 1997 hedging activities, specifically a $2.9
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<PAGE> 18
million reduction in liquids revenue and a $7.9 million reduction in gas
revenue, net realized prices were reduced to $17.34 per Bbl and $2.41 per Mcf
for liquids and natural gas, respectively.
Lease Operating Expenses. Lease operating expenses were $99.2 million in
1998 compared to $77.2 million in 1997. The increase related primarily to new
oil and gas properties acquired in late 1997 and early 1998. On an equivalent
unit of production basis, lease operating expenses increased to $4.66 per BOE in
1998 from $4.33 per BOE in 1997, an increase attributable to slightly higher
lease operating expenses associated with new properties acquired and higher 1998
workover costs.
Depletion, Depreciation and Amortization("DD&A"). DD&A expense increased
to $420.9 million in 1998 from $313.3 million for 1997. DD&A expense, not
including impairment provisions, was $145.9 million in 1998 compared to $113.3
million in 1997. The increase was principally attributable to higher production
volumes and an increase in the rate from $6.36 per BOE in 1997 to $6.84 per BOE
in 1998. In addition, the Company recorded non-cash impairments of oil and gas
assets in the fourth quarter of 1998 for $275 million and $200 million in the
fourth quarter of 1997.
General and Administrative Expense. General and administrative expense,
net of overhead reimbursements and capitalized internal costs, was $17.2 million
in 1998 compared with $15.2 million in 1997. This increase was attributable to
the overall growth of the Company. On a barrel equivalent basis, general and
administrative expenses decreased by 5% to $.81 per BOE in 1998 from $.85 per
BOE in 1997.
Other Income. Interest and other income decreased to $1.6 million in 1998
from $3.4 million in 1997. The decrease was primarily attributable to a decline
in the Company's equity in the earnings of Cook Inlet Pipeline Company, a 30%
owned affiliate acquired in early 1997.
Interest Expense. Interest expense, net of amounts capitalized, increased
to $48.1 million in 1998, compared to the $32.4 million recorded in 1997. The
increase in interest expense was due primarily to increased long-term debt
levels.
Income Tax Provision/Benefit. Due to net losses incurred during 1998, an
income tax provision was not recorded during 1998. The $20.6 million income tax
benefit reported in 1997 resulted from the $200 million non-cash impairment of
oil and gas properties recorded in the fourth quarter of 1997.
LIQUIDITY AND CAPITAL RESOURCES
The Company makes substantial capital expenditures for the exploration and
development of oil and natural gas reserves in the ordinary course of business.
Historically, the Company has financed its capital expenditures, debt service
and working capital requirements with cash flow from operations, public
offerings of equity, private offerings of debt, asset sales, a senior credit
facility and other financings. Cash flow from operations is sensitive to the
prices the Company receives for its oil and natural gas. A reduction in planned
capital spending or an extended decline in oil and gas prices could result in
less than anticipated cash flow from operations in the current fiscal year and
in later years which could have a material adverse affect on the Company. Such a
decline in prices or production could also adversely affect the amount that the
Company could borrow under its credit facility. The availability of capital to
the energy industry, in general, and from the public equity and debt markets, is
also influenced by prevailing market sentiment that might be totally unrelated
to the industry's current performance.
On March 21, 1999, the Company and its wholly-owned subsidiary, Forcenergy
Resources Inc., filed a voluntary petition for relief under Chapter 11 of Title
11 of the United States Code in order to facilitate the restructuring of the
Company's long-term debt, revolving credit, trade and other obligations. The
filing was made in the U.S. Bankruptcy Court for the Eastern District of
Louisiana in New Orleans. The Company continued to operate as a
debtor-in-possession subject to the Bankruptcy Court's supervision and orders
until February 15, 2000, at which time the Plan of Reorganization (the "Plan" or
"Reorganization") became effective (See Notes 1, 2 and 6 to the Consolidated
Financial Statements included elsewhere in this Form 10-K).
15
<PAGE> 19
In conjunction with the Reorganization, the Company replaced the prior
senior credit facility (the "Prior Senior Credit Facility") with a new senior
credit facility with essentially the same group of banks ("New Senior Credit
Facility"). The New Senior Credit Facility consists of a $250 million Revolving
Credit Facility (the "Revolver") and a $70 million Term Loan (the "Term Loan").
The amount that can be borrowed under the Revolver is further subject to a
borrowing base, which has been established initially at $250 million through
February 15, 2001. The Revolver provides for borrowings on a revolving basis
through August 15, 2003, at which time all outstanding amounts under the
Revolver become due and payable. Advances under the Revolver bear interest at
prime plus 1.5% or LIBOR plus 2% per annum at the election of the Company. The
agreement provides for a commitment fee on the unused portion of the Revolver at
.50% due quarterly. The borrowing base is subject to semi-annual
re-determination after the first re-determination on February 15, 2001. The
terms of the Term Loan provide for mandatory quarterly principal repayments of
$2.5 million commencing on March 31, 2001, with a $50 million balloon repayment
at maturity on August 15, 2003. Interest is payable monthly on the Term Loan at
prime plus 3% or at LIBOR plus 3.5%.
On March 20, 2000 the Company collected $40.0 million in proceeds from the
issuance of preferred stock and warrants as part of the Reorganization (See Note
2 to the Consolidated Financial statements included elsewhere in this Form
10-K). The proceeds were used to repay borrowings outstanding under the
Revolver. At March 28, 2000 $164.1 million was drawn under the Revolver with
$80.5 million available for use for general corporate purposes.
The Company has historically funded its operations, acquisitions, capital
expenditures and working capital requirements from cash flow from operations,
bank borrowings and private and public placements of debt and equity securities.
The Company's primary sources of funds for each of the past three years were as
follows:
<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.
16
<PAGE> 20
The Company has historically entered into various financial instruments
with off-balance sheet risk, to reduce its exposure to changing commodity
prices. The Company normally utilizes these arrangements for portions of its
current oil and gas production to achieve more predictable cash flows and to
reduce its exposure to fluctuations in oil and gas prices for varying time
periods. The remaining portion of current production is not hedged so as to
provide the Company the opportunity to benefit from increases in prices on that
portion of the production, should price increases materialize. The Company had
various instruments in place on the Petition Date, all of which were cancelled
at the option of the counterparties subsequent to the Company's Chapter 11
bankruptcy filing. The Company received $5.5 million (fair market value of the
contracts at the time) in cash in April 1999 in final settlement of the
contracts. The settlements were included in oil and gas sales in the
Consolidated Statements of Operations for the year ended December 31, 1999.
The Company subsequently entered into several new financial hedging
contracts ("Swaps") with respect to its future oil and natural gas production.
Under these agreements, monthly settlements are based on the differences between
the prices specified in the instrument and/or the settlement price of certain
oil and gas futures contracts quoted on the New York Mercantile Exchange
("NYMEX"). In instances where the applicable settlement price is less than the
price specified in the contract, the Company receives a settlement based on the
difference and in instances where the applicable settlement price is higher than
the specified prices, the Company pays an amount based on the difference. Swap
contracts in place at December 31, 1999 (and including contracts entered into
subsequent to year-end) on future oil production were as follows:
<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 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>
WEIGHTED AVERAGE
VOLUME IN NYMEX
MCF 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
17
<PAGE> 21
increase the amount of the deposit to the extent that the market price of oil
and gas is higher than the contract price. Subsequent to the year-end the
Company made additional deposits of $4 million.
As an additional hedge on natural gas prices, the Company has also
committed to fixed prices on approximately 26 MMCF per day, or 18%, of its
estimated first quarter 2000 natural gas production at an average price of $2.69
per Mcf under existing sales contracts with the Company's purchaser of physical
production. The Company may enter into additional arrangements in the future as
part of its strategy to reduce exposure to commodity price fluctuations.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standard No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS No. 133"). The statement requires companies to
report the fair market value of derivatives on the balance sheet and record in
income or other comprehensive income, as appropriate, any changes in the fair
value of the derivative. Statement No. 133 will become effective with respect to
the Company on January 1, 2001. The Company is currently evaluating the impact
of SFAS No. 133.
18
<PAGE> 22
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:
<TABLE>
<S> <C>
2.1 First Amended Joint Plan of Reorganization of Forcenergy Inc
and Forcenergy Resources Inc. dated October 26, 1999. (Filed
as Exhibit 2.1 to the Company's Form 8-K filed on January
26, 2000 and incorporated herein by reference).
2.2 Motion for Authority to File Debtors' Second Immaterial
Modification. (Filed as Exhibit 2.2 to the Company's Form
8-K filed on January 26, 2000 and incorporated herein by
reference).
2.3 Debtors' Joint Plan Supplement dated November 8, 1999 (forms
of reorganization documents). (Filed as Exhibit 2.3 to the
Company's Form 8-K filed on January 26, 2000 and
incorporated herein by reference).
2.4 Motion to Substitute Revised Warrant Agreements to be Filed
as Part of Debtor's Amended Plan Supplement dated December
10, 1999. (Filed as Exhibit 2.4 to the Company's
Form 8-K filed on January 26, 2000 and incorporated herein
by reference).
2.5 Findings of Fact and Conclusions of Law and Order Confirming
the Joint Plan of Reorganization of Forcenergy Inc and
Forcenergy Resources Inc. dated January 19, 2000. (Filed as
Exhibit 2.5 to the Company's Form 8-K filed on January 26,
2000 and incorporated herein by reference).
3.1 Amended and Restated Certificate of Incorporation of
Forcenergy Inc dated as of February 15, 2000. (Filed as
Exhibit 3.1 to the Company's Form 8-K filed on February 16,
2000 and incorporated herein by reference).
3.2 Amended and Restated Bylaws of Forcenergy Inc dated as of
February 15, 2000. (Filed as Exhibit 3.2 to the Company's
Form 8-K filed on February 16, 2000 and incorporated herein
by reference).
4.1 Specimen Common Stock Certificate. (Filed as Exhibit 4.1 to
the current report on
Form 8-K filed on February 16, 2000 and incorporated herein
by reference).
</TABLE>
19
<PAGE> 23
<TABLE>
<S> <C>
4.2 Certificate of Designation of the Powers Preferences and
Relative, Participating, Optional and other Special Rights
of 14% Series A Cumulative Preferred Stock. (Filed as
Exhibit 4.2 to the current report on Form 8-K filed on
February 16, 2000 and incorporated herein by reference).
4.3 Specimen 14% Series A Cumulative Preferred Stock
Certificate. (Filed as Exhibit 4.3 to the current report on
Form 8-K filed on February 16, 2000 and incorporated herein
by reference).
4.4 Warrant Agreement (Four Year Warrants), dated as of February
15, 2000 between Forcenergy Inc and American Stock Transfer
and Trust Company, including the form of Warrant Certificate
for the Four Year Warrants. (Filed as Exhibit 4.4 to the
Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
4.5 Warrant Agreement (Five Year Warrants), dated as of February
15, 2000 between Forcenergy Inc and American Stock Transfer
and Trust Company, including the form of Warrant Certificate
for the Five Year Warrants. (Filed as Exhibit 4.5 to the
Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
4.6* Warrant Agreement (Subscription Warrants), dated as of March
20, 2000 between Forcenergy Inc and American Stock Transfer
and Trust Company, including the form of Warrant Certificate
for the Subscription Warrants.
10.1 Forcenergy Inc 1999 Stock Plan. (Filed as Exhibit 10.1 to
the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.2 Forcenergy Inc 1999 Employee Stock Purchase Plan. (Filed as
Exhibit 10.2 to the Company's Form 8-K filed on February 16,
2000 and incorporated herein by reference).
10.3 Registration Rights Agreement dated as of February 15, 2000
among Forcenergy Inc and the parties identified on the
signature pages thereto. (Filed as Exhibit 10.3 to the
Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.4 Employment Agreement dated as of February 15, 2000 between
Forcenergy Inc and Stig Wennerstrom. (Filed as Exhibit 10.4
to the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.5 Employment Agreement dated as of February 15, 2000 between
Forcenergy Inc and J. Russell Porter. (Filed as Exhibit 10.5
to the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.6 Employment Agreement dated as of February 15, 2000 between
Forcenergy Inc and Thomas F. Getten. (Filed as Exhibit 10.6
to the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.7 Employment Agreement dated as of February 15, 2000 between
Forcenergy Inc and E. Joseph Grady. (Filed as Exhibit 10.7
to the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.8 Employment Agreement dated as of February 15, 2000 between
Forcenergy Inc and Gary E. Carlson. (Filed as Exhibit 10.8
to the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.9 Employment Agreement dated as of February 15, 2000 between
Forcenergy Inc and Mark Yelverton. (Filed as Exhibit 10.9 to
the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.10 Employment Agreement dated as of February 15, 2000 between
Forcenergy Inc and Robert G. Gerdes. (Filed as Exhibit 10.10
to the Company's Form 8-K filed on February 16, 2000 and
incorporated herein by reference).
10.11 Employment Agreement dated as of December 10, 1999 between
Forcenergy Inc and the Standby Purchasers named therein.
(Filed as Exhibit 10.11 to the Company's Form 8-K filed on
February 16, 2000 and incorporated herein by reference).
</TABLE>
20
<PAGE> 24
<TABLE>
<S> <C>
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
</TABLE>
---------------
* Filed with original Annual Report on Form 10-K for the year ended December 31,
1999.
b. REPORTS ON FORM 8-K
No Current Reports on Form 8-K were filed by the Company during the fourth
quarter of 1999.
21
<PAGE> 25
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Dated: November 3, 2000
FORCENERGY INC
By: /s/ E. JOSEPH GRADY
------------------------------------
E. Joseph Grady
Vice President -- Chief Financial
Officer
22
<PAGE> 26
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Forcenergy Inc
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, stockholders' equity (deficit)
and cash flows present fairly, in all material respects, the financial position
of Forcenergy Inc ("Successor") at December 31, 1999 and Forcenergy Inc.
("Predecessor") at December 31, 1998 (collectively, the "Company"), and the
results of the Company's operations and cash flows for each of the three years
in the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States, which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As discussed in Notes 1 and 2 to the consolidated financial statements, on
March 21, 1999, the Company filed a voluntary petition for relief, under Chapter
11 of Title 11 of the United States Code ("Chapter 11"), with the United States
Bankruptcy Court for the Eastern District of Louisiana. The Company's Plan of
Reorganization, as amended, became effective on February 15, 2000 and the
Company emerged from Chapter 11. In connection with its emergence from Chapter
11, the Company adopted Fresh-Start Reporting as of December 31, 1999.
PricewaterhouseCoopers LLP
Miami, Florida
March 17, 2000
F-1
<PAGE> 27
FORCENERGY INC
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
SUCCESSOR PREDECESSOR
COMPANY COMPANY
------------ ------------
DECEMBER 31, DECEMBER 31,
1999 1998
------------ ------------
(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> 28
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 AND
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 and 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> 29
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> 30
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> 31
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND BASIS OF PRESENTATION
ORGANIZATION
Forcenergy Inc, a Delaware Corporation, and its subsidiaries ("Forcenergy"
or the "Company"), is an independent oil and gas company engaged in the
exploration, acquisition, development, exploitation and production of oil and
natural gas. The Company's principal areas of operation are the Gulf of Mexico
and the Cook Inlet, Alaska.
Forcenergy and its wholly-owned subsidiary Forcenergy Resources Inc.
("Resources") emerged from bankruptcy effective February 15, 2000 (See Note 2
for a more detailed discussion on the reorganized entity). The original
voluntary petition for relief under Chapter 11 of Title 11 of the United States
Code was filed on March 21, 1999 (the "Petition Date") in order to facilitate
the restructuring of the Company's long-term debt, revolving credit, trade debt
and other obligations. The filing was made in the United States Bankruptcy Court
for the Eastern District of Louisiana in New Orleans (the "Bankruptcy Court").
While the Company operated under Chapter 11, certain claims against the Company
at the Petition Date were stayed while the Company continued its operations as a
debtor-in-possession. On January 19, 2000, the Bankruptcy Court approved the
Company's Plan of Reorganization (the "Plan"), which became effective on
February 15, 2000 (the "Emergence Date").
The consolidated financial statements as of December 31, 1999 and for the
year then ended included herein reflect accounting principles set forth in the
American Institute of Certified Public Accountants Statement of Position 90-7
"Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,"
("SOP 90-7"), which provides guidance for financial reporting by entities that
have filed voluntary petitions for relief under, and have reorganized in
accordance with, the Bankruptcy Code. In accordance with guidance provided by
SOP 90-7 the consummation of the Plan (the "Reorganization") has been reflected
as though effective on December 31, 1999 (the "Effective Date").
Under provisions of SOP 90-7 and fresh start reporting (See Note 2) the
December 31, 1999 Consolidated Balance Sheet is the opening balance sheet of the
reorganized company (the "Successor Company"). The December 31, 1999
Consolidated Balance Sheet includes all adjustments necessary to reflect assets
at reorganization value and the Plan's treatment of creditor claims and previous
equity interests. Since the December 31, 1999 Consolidated Balance Sheet was
affected by the Reorganization and fresh-start reporting adjustments, it is not
comparable in certain material respects to any of the consolidated balance
sheets shown in these financial statements as of any prior date. The
Consolidated Statements of Operations and Cash Flows for the years ended
December 31, 1999, 1998 and 1997 each reflect the activities of the Company
prior to the Effective Date (the "Predecessor Company"), however, the statements
for 1999 do reflect certain Reorganization-related charges and credits.
NOTE 2 -- REORGANIZATION AND FRESH-START REPORTING
In August 1999, the Company filed with the Bankruptcy Court a disclosure
statement that included the proposed Plan. The Plan set forth the means for
satisfying claims, including liabilities subject to compromise and equity
interests in the Company. The disclosure statement was approved by the
bankruptcy court on October 22, 1999, and the Plan was confirmed by the
bankruptcy court on January 19, 2000.
F-6
<PAGE> 32
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
On February 15, 2000, the Company and its existing bank lending group
entered into a new senior credit facility (the "New Senior Credit Facility")
that replaced the Company's prior senior credit facility (the "Prior Senior
Credit Facility") and satisfied all pre-petition claims thereunder. Pursuant to
provisions of the Plan and the New Senior Credit Facility the Company paid $66.9
million in cash on the Effective Date to the bank group, which included a
repayment of $40 million in principal outstanding under the Prior Senior Credit
Facility, $24.3 million in accrued interest, and loan fees and administrative
expenses incurred by the bank group of $2.6 million. The $2.6 million of
administrative expenses were accrued at December 31, 1999, and were included as
reorganization items in the Consolidated Statement of Operations for the year
ended December 31, 1999.
In accordance with provisions of the Plan, all outstanding shares of the
common stock of the Predecessor Company (the "Old Common Stock") were canceled
effective as of the Emergence Date and the holders of Old Common Stock as of the
January 28, 2000 record date received, on a pro-rata basis. 960,000 shares of
New Common Stock and associated warrants to purchase 240,000 shares of New
Common Stock at $16.67 per share (expiring on February 15, 2004) and warrants to
purchase 240,000 shares of New Common Stock at $20.83 per share (expiring on
February 15, 2005). The cancellation and issuance of these equity instruments
was reflected in the Successor Company consolidated Balance Sheet and the
Consolidated Statement of Stockholder's Equity at December 31, 1999.
The Plan also provides for the payment of administrative costs incurred
during the pendency of the Reorganization (primarily legal and financial
advisory fees). The Company paid $5.0 million in administrative expenses during
1999 and accrued another $11.2 million at December 31, 1999, all of which are
included in the Consolidated Statement of Operations for the year ended December
31, 1999, as a reorganization item.
F-7
<PAGE> 33
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Plan required the Company to raise $40 million in additional equity
capital. This was to be accomplished through a rights offering to unsecured
claimants to purchase units that include one share of 14% Series A Cumulative
Preferred Stock (the "Preferred Stock") and a warrant (the "Subscription
Warrants") to purchase 45 shares of New Common Stock (collectively, the "Rights
Offering") for $1,000 per unit. On March 20, 2000 the Rights Offering was closed
with the issuance of 40,000 shares of Preferred Stock and Subscription Warrants
to purchase 1,800,000 shares of New Common Stock. The net proceeds from the
Rights Offering aggregated $38.8 million, net of offering costs of $1.2 million.
The proceeds were used to pay down amounts outstanding under the New Senior
Credit Facility (see proforma later in this footnote). The Preferred Stock is
perpetual in nature and quarterly dividends are payable commencing March 31,
2000 in additional shares of Preferred Stock for the first four years
thereafter. The Preferred Stock is non-convertible, and is callable by the
Company at any time for 100% of liquidation preferences plus accrued but unpaid
dividends. Holders of each share of Preferred Stock are entitled to one vote in
matters requiring shareholder approval and vote as one class with the common
shareholders. Only upon certain types of changes in control, the Company must
redeem all outstanding Preferred Stock at 101% of liquidation preference plus
accrued and unpaid dividends. The Subscription Warrants entitle the holder to
purchase shares of New Common Stock at an initial exercise price of $10.00 per
share. The Subscription Warrants are detachable and expire on March 15, 2010 or
upon notice of expiration by the Company after March 20, 2004 if the market
price of the New Common Stock has exceeded the exercise price of the
Subscription Warrants for a period of 30 consecutive trading days. If the
Company fails to pay a dividend for any two consecutive quarters or any six
quarters in the aggregate, the holders of the Preferred Stock voting as a single
class shall be entitled to elect two members of the board of directors. The
terms of the Preferred Stock include other events of default, representations
and warranties and affirmative and negative covenants typical for instruments of
this type.
Pursuant to the guidance provided by SOP 90-7 the Company adopted the
provisions of fresh-start reporting and as discussed earlier the Reorganization
was reflected at December 31, 1999. Under fresh-start reporting, the overall
fair market value of the Company ("Reorganization Value") was allocated to the
Successor Company's net assets using the purchase method of accounting.
The Reorganization Value of $678.3 million was developed by the Company and
the Company's independent financial advisors and represents the fair market
value of working capital and the Company's oil and gas reserves. That value,
less the New Senior Credit Facility, results in an equity value of $240 million.
Working capital assets and liabilities of the Company at any given time as
reflected in the consolidated financial statements are stated at fair market
value.
The methodologies used in the valuation of oil and gas reserves were the
discounted cash flow ("DCF") and the Comparable Transactions Methods. The DCF
valuation is based on the present value of the pre-tax cash flows from the
Company's reserves discounted at 10% using escalated pricing consistent with the
New York Mercantile Exchange ("NYMEX") futures curve, as of August 12, 1999
through 2001 and held flat thereafter at approximately $18.00 per barrel for oil
and $2.50 per million cubic feet for gas. Cash flow has been risk adjusted and
discounted based on industry accepted factors for reserves valuation. The DCF
value of $510 million was compared to observed 1999 transaction values by region
(Comparable Transactions Method) and deemed to be in a reasonable range of value
for present industry conditions.
Reorganization Value was less than the recorded amount of net assets
immediately prior to emergence by $56.0 million, which was reflected as a
revaluation of assets to fair market value under reorganization items in the
Statement of Operations for the year ended December 31, 1999. See fresh-start
reporting adjustment (b) below.
F-8
<PAGE> 34
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The effects of the Reorganization and related fresh-start reporting
adjustments at December 31, 1999, are shown in the following consolidated
balance sheet. Also presented is a proforma presentation as if all of the
financing transactions and claims settlements incorporated in the Plan of
Reorganization had been consummated as of December 31, 1999:
<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:
(a) Discharge of indebtedness.
(b) Revaluation of the Company's oil and gas properties to fair market
value.
(c) Elimination of deferred financing costs associated with Prior Senior
Credit Facility.
(d) Establish the New Senior Credit Facility.
(e) Cancellation of the Old Common Stock and elimination of accumulated
deficit.
(f) Issuance of 24 million shares of New Common Stock.
Proforma Adjustments:
(a) Issuance of Redeemable Preferred Stock and Subscription Warrants.
(b) Satisfaction of remaining pre-petition claims.
(c) Payment of accrued reorganization expenses.
(d) Payment of accrued interest and principal on the New Senior Credit
Facility.
F-9
<PAGE> 35
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
Forcenergy Inc, and its subsidiaries after elimination of all intercompany
transactions and balances.
ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities. Actual results
could differ from those estimates.
CASH/CASH EQUIVALENTS
The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents. The Company
maintains cash deposits with several financial institutions. At certain times,
these deposits may exceed federally insured limits.
ACCOUNTS RECEIVABLE
Accounts receivable relate primarily to sales of oil and gas production and
amounts due from joint interest partners for expenditures made by the Company on
behalf of such partners. The Company reviews the financial condition of
potential purchasers and partners prior to signing sales or joint interest
agreements. The allowance for doubtful accounts was $2,000,000 at December 31,
1999 and 1998. The Company requires certain forms of financial assurance from
its most significant customers.
OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for oil and gas
properties whereby all productive and non-productive exploration, development
and acquisition costs incurred for the purpose of finding oil and gas reserves
are capitalized. Such capitalized costs include lease acquisition, geological
and geophysical work, delay rentals, drilling, completing and equipping oil and
gas wells, together with internal costs directly attributable to property
acquisition, exploration and development activities. No gain or loss is
recognized upon the sale or other disposition of oil and gas properties, except
in unusually significant transactions.
Depreciation, depletion and amortization of oil and gas properties are
computed on a composite unit-of-production method based on estimated proved
reserves. All costs associated with evaluated oil and gas properties, including
an estimate of future development, restoration, dismantlement and abandonment
costs associated therewith, are included in the computation base. The Company
evaluates all unevaluated oil and gas properties on a quarterly basis to
determine if any impairment has occurred or if the property has been otherwise
evaluated. If a property has been evaluated, or if there is determined to be any
impairment, costs related to the particular unevaluated properties are
reclassified as an evaluated oil and gas property, and thus subject to
amortization if there are proved reserves associated with the related cost
center. Otherwise, such impairment will be recognized in the period in which it
occurs.
Under the Securities and Exchange Commission's full cost accounting rules,
the Company reviews the carrying value of its oil and gas properties each
quarter. Under full cost accounting rules, capitalized costs of oil and gas
properties, net of deferred tax reserves, may not exceed the present value of
estimated future net revenues from proved reserves, discounted at 10 percent,
plus the lower of cost or fair market value of unproved properties, as adjusted
for related tax effects. Application of this rule generally requires pricing
F-10
<PAGE> 36
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
future production at the unescalated oil and gas prices in effect at the end of
each fiscal quarter and requires a permanent write-down of capitalized costs if
the "ceiling" is exceeded, even if prices declined for only a short period of
time.
Under the provisions of fresh-start reporting the Company restated its oil
and gas properties to fair market value ($510 million) at December 31, 1999
resulting in a non-cash charge to the Consolidated Statement of Operations for
the year ended December 31, 1999 of approximately $54 million, which is
reflected as a reorganization item (See Note 2). During the fourth quarter of
1998 and 1997 the Company recognized non-cash impairments of recorded oil and
gas assets amounting to $275 million and $200 million ($162.8 million after
tax), respectively, pursuant to the above discussed "ceiling test" provisions.
The majority of the Company's oil and gas properties are located in the
Gulf of Mexico and Cook Inlet, Alaska.
REVENUE RECOGNITION
During 1999, 1998 and 1997, the Company maintained a hedging program on a
portion of its estimated future production to provide a certain minimum level of
cash flow from its sales of crude oil and natural gas (See Note 10). Any hedging
gains or losses under these contracts are recognized in revenue upon monthly
settlement of hedged production. All commodity price-hedging contracts in place
prior to the Petition Date were cancelled during 1999 at the option of the
counterparties subsequent to the Chapter 11 bankruptcy filing. The Company has
subsequently entered into new contracts in 1999 and 2000 (See Note 10).
STOCK-BASED COMPENSATION
Statement of Financial Accounting Standards No. 123 "Accounting for
Stock-Based Compensation" ("SFAS No. 123") encourages, but does not require,
companies to record compensation costs for stock-based employee compensation
plans at fair value. The Company has chosen to continue to account for
stock-based employee compensation using the intrinsic value method prescribed in
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees". Accordingly, compensation cost for stock options and warrants is
measured as the excess, if any, of the quoted market price of the Company's
stock at the date of the grant over the amount an employee must pay to acquire
the stock (See Note 8).
INCOME TAXES
The Company follows the asset and liability approach to account for income
taxes. Under this method, deferred taxes are recognized for temporary
differences between the book and tax basis of assets and liabilities. These
temporary differences are measured using applicable enacted tax rates and
provisions of enacted tax laws.
EARNINGS PER SHARE
During 1997, the Company adopted Statement of Financial Accounting
Standards No. 128 "Earnings Per Share" ("SFAS No. 128") and has restated all
years presented in accordance therewith. SFAS No. 128 requires a dual
presentation of basic and diluted earnings per share ("EPS") on the face of the
statement of operations. Basic EPS is computed by dividing income available to
common stockholders by the weighted-average number of common shares for the
period. Diluted EPS reflects the potential dilution that could occur if
securities or other contracts to issue common stock were exercised or converted
into common stock or resulted in the issuance of common stock that would then
share in earnings (See Note 9).
F-11
<PAGE> 37
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ENVIRONMENTAL EXPENDITURES
Environmental expenditures relating to current operations are expensed or
capitalized, as appropriate, depending on whether such expenditures provide
future economic benefits. Liabilities are recognized when the expenditures are
considered probable and can be reasonably estimated. Measurement of liabilities
is based on currently enacted laws and regulations, existing technology and
undiscounted site-specific costs. Generally, such recognition coincides with the
Company's commitment to a formal plan of action.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company includes fair value information in the Notes to Consolidated
Financial Statements when the fair value of its financial instruments can be
determined and is different from the book value. The Company generally assumes
the book value of those financial instruments that are classified as current
approximate fair value because of the short maturity of these instruments. For
non-current financial instruments, the Company uses quoted market prices or, to
the extent that there are no available quoted market prices, market prices for
similar instruments.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standard No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS No. 133"). The statement requires companies to
report the fair market value of derivatives on the balance sheet and record in
income or other comprehensive income, as appropriate, any changes in the fair
value of the derivative. SFAS No. 133 will become effective with respect to the
Company on January 1, 2001. The Company is currently evaluating the impact of
SFAS No. 133.
NOTE 4 -- ACQUISITIONS AND MERGERS
The company had no material property acquisitions in 1999 during the
pendency of the bankruptcy proceedings.
1998 ACQUISITIONS
The Company completed several acquisitions during 1998 at an aggregate cost
of approximately $54.0 million. The aggregate effect of these acquisitions on
the results of operations of the Company for the periods presented was not
material.
1997 ACQUISITIONS
The Company completed several acquisitions during 1997 at an aggregate cost
of approximately $220.5 million. The three most significant acquisitions, all of
which were accounted for as purchases, are discussed below. The aggregate effect
of other acquisitions on the results of operations of the Company for the
periods presented was not material.
On January 21, 1997, Forcenergy acquired all of the outstanding stock of
Great Western Resources, Inc. ("Great Western") for approximately $48.3 million.
The net assets acquired consisted primarily of producing oil and gas properties.
The results of operations of the acquired properties are included in the
Company's results of operations beginning January 21, 1997.
On June 4, 1997, Forcenergy acquired a 97.75% working interest in certain
oil and gas properties located in the Cook Inlet, Alaska from Stewart Petroleum
Company ("Stewart") for $18.7 million and assumed operations of the field. The
results of operations for the acquired properties are included in the Company's
operations beginning June 4, 1997. In October 1997 the Company increased its
interest in this field to 100%.
F-12
<PAGE> 38
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On October 22, 1997, Forcenergy, in separate transactions, acquired all of
the outstanding common stock of Edisto Resources Corporation ("Edisto") and
Convest Energy Corporation ("Convest"). Forcenergy issued approximately 2.8
million shares of common stock valued at $34.96 per share, or approximately
$98.9 million. The shareholders of Edisto also received $69.3 million in cash
from balances Forcenergy received in the merger. Edisto owned 73% of the
outstanding common stock of Convest. The net assets acquired consisted
principally of producing oil and gas properties. The results of operations of
the acquired properties are included in the Company's operations beginning
October 22, 1997.
FORCENERGY AB ACQUISITION
On December 19, 1997 Forcenergy made a public tender offer for all of the
outstanding shares of Forcenergy AB ("FAB"). FAB was formed in 1990 to provide
capital for Forcenergy's oil and gas operations in the United States and held
8,740,486 shares of Forcenergy common stock, its only significant asset. During
1998, the Company issued approximately 7.9 million shares valued at $27 per
share (the price of the Company's common stock on the date the tender offer was
initiated in 1997) in exchange for the tendered shares. The 8,740,486 Forcenergy
shares owned by FAB were controlled by Forcenergy, and for accounting and voting
purposes were no longer considered outstanding. The acquisition was accounted
for as a purchase with results of operations included beginning March 31, 1998.
During the fourth quarter of 1999, the Company sold all of the outstanding
shares of FAB for $5.5 million in cash, resulting in a gain on the sale of $5.5
million, which is included in interest and other income in the Consolidated
Statement of Operations for the year ended December 31, 1999. The Forcenergy
shares held by FAB discussed above were cancelled pursuant to the transaction.
NOTE 5 -- PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment at December 31, 1999 and 1998
were as follows (in thousands):
<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.
F-13
<PAGE> 39
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During the years ended December 31, 1999, 1998 and 1997 the Company
capitalized interest of $2.2 million, $4.4 million and $4.2 million,
respectively, on expenditures made in connection with exploration and
development projects on significant unproved properties that are not subject to
current depletion, depreciation or amortization. Interest is capitalized only
for the period during which activities to bring the properties to their intended
use are ongoing.
The following sets forth the composition of capitalized costs excluded from
the depletion, depreciation, and amortization base at December 31, 1999 and 1998
(in thousands):
<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.
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
F-14
<PAGE> 40
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
dividends and additional debt or liens. The Company was in violation of several
of the financial covenants as of December 31, 1999 and 1998. As discussed in
Note 1, all amounts drawn under the Prior Senior Credit Facility at December 31,
1998, were shown as liabilities subject to compromise pursuant to the Chapter 11
filing.
Pursuant to the Reorganization the Company and substantially the same bank
lending group entered into the New Senior Credit Facility on February 15, 2000,
replacing the Prior Senior Credit Facility (See Notes 1 and 2).
NEW SENIOR CREDIT FACILITY
The New Senior Credit Facility consists of a $250 million Revolving Credit
Facility (the "Revolver") and a $70 million Term Loan (the "Term Loan").
The amount that can be borrowed under the Revolver is further subject to a
borrowing base which has been established at $250 million through February 15,
2001. The Revolver provides for borrowings on a revolving basis through August
15, 2003 at which time all outstanding amounts under the Revolver become due and
payable. Advances under the Revolver bear interest at prime plus 1.5% or LIBOR
plus 2% per annum at the election of the Company. The agreement provides for a
commitment fee on the unused portion of the Revolver at .50% due quarterly. The
borrowing base is subject to semi-annual re-determination after the first
re-determination on February 15, 2001.
The terms of the Term Loan provide mandatory quarterly principal repayments
of $2.5 million commencing on March 31, 2001, with a $50 million balloon
repayment at maturity on August 15, 2003. Interest is payable monthly at the
prime rate plus 3% or LIBOR plus 3.5%.
At March 28, 2000 the Company had drawn down $164.1 million under the
Revolver under the New Senior Credit Facility and an additional $5.4 million of
availability was utilized for outstanding letters of credit issued under the
Revolver, leaving $80.5 million available for general corporate purposes.
The New Senior Credit Facility is secured by substantially all of the
Company's oil and gas properties and contains events of default, representation
and warranties and covenants typical for facilities of this type.
SENIOR SUBORDINATED NOTES
On February 15, 2000, but effective December 31, 1999 for purposes of these
financial statements, all of the outstanding Senior Subordinated Notes were
exchanged for New Common Stock pursuant to the Reorganization (See Notes 1 and
2). In accordance with SOP 90-7 the Company did not accrue interest on the
Senior Subordinated Notes after the Petition Date as it was unlikely such
interest would be paid under the Plan. The amount of such unaccrued contractual
interest from March 21, 1999, to December 31, 1999, was $26.2 million. The
holders of the Notes did not pursue this interest as a part of their claims.
On November 6, 1996, the Company issued an aggregate principal amount of
$175 million of 9 1/2% Senior Subordinated Notes (the "9 1/2% Notes") that
matured on November 1, 2006. The 9 1/2% Notes were issued under an Indenture
which provided that interest was payable semiannually, in arrears, on May 1 and
November 1 of each year, commencing May 1, 1997, with principal due at maturity.
On February 14, 1997, the Company issued an aggregate principal amount of
$200 million in 8 1/2% Senior Subordinated Notes priced at $99.338, with an
effective yield to maturity of 8.6% (the "8 1/2% Notes"), that matured on
February 15, 2007. The 8 1/2% Notes were issued under an Indenture which
provided that interest on the 8 1/2% Notes was payable in cash in arrears
semiannually on February 15 and August 15 of each year, commencing August 15,
1997 with principal due at maturity.
F-15
<PAGE> 41
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's aggregate long-term debt maturities for the next five
calendar years under the New Senior Credit Facility are as follows (in
thousands):
<TABLE>
<S> <C>
2000...................................................... $ --
2001...................................................... 10,000
2002...................................................... 10,000
2003...................................................... 294,473
--------
Total............................................. $314,473
========
</TABLE>
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>
The Company's deferred income tax assets were comprised of the following
differences between financial and tax reporting at December 31, 1999 and 1998
(in thousands):
<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 asset.................................. $ -- $ --
========== =========
</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
F-16
<PAGE> 42
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
this carryforward is subject to limitations under the Internal Revenue Code.
Section 382 of the Code provides for limitations on the utilization of available
net operating loss carryforwards following a change in ownership. The Company's
annual limitation on the utilization of its net operating losses is
approximately $13.8 million.
Deferred tax assets will not provide an income tax benefit when realized.
Rather, the future realization of these assets will result in an increase in
stockholders' equity.
As a result of its reorganization under Chapter 11 of Title 11 of the
United States Code, the Company realized cancellation of indebtedness income of
approximately $171.1 million. Although this income is not taxable to the Company
for federal or state tax purposes, the Company's net operating loss
carryforwards were reduced by a corresponding amount.
NOTE 8 -- STOCK BASED COMPENSATION PLANS
The Company has adopted the disclosure provisions of SFAS No. 123.
Accordingly, no compensation costs have been recorded for the stock options and
warrants as the exercise price of all options granted was the fair market value
on the date of grant.
STOCK OPTION PLANS
The following table summarizes the Predecessor Company's stock option
activity for 1997, 1998 and 1999 under the 1995 Forcenergy Stock Option Plan,
which was cancelled on February 15, 2000 in conjunction with the Reorganization
(See Notes 1 and 2):
<TABLE>
<CAPTION>
WEIGHTED
AVERAGE
NUMBER OPTION PRICE EXERCISE
OF SHARES PER SHARE PRICE
---------- --------------------- --------
<S> <C> <C> <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).
F-17
<PAGE> 43
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
If compensation expense for the stock options and warrants had been
determined and recorded based on the fair value on the grant date, and using the
Black-Scholes option pricing model to estimate the theoretical future value of
those options, the Company's net income (loss) and net income (loss) per share
amounts would have been reduced to the pro forma amounts indicated below:
<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>
In February 1999, all options then outstanding were cancelled and reissued
with an exercise price of $1.275 per share, the then current fair market value
of the underlying stock on that date plus 20%. All other terms of options
previously granted to non-executives remained unchanged. The number of options
held by executives and directors was reduced by approximately 114,000 shares. As
a result of this repricing of options, the plan changed from a fixed option plan
to a variable plan for accounting purposes.
Effective February 15, 2000, the Company terminated the 1995 Stock Option
Plan and adopted the Forcenergy Inc 1999 Stock Option Plan (the "1999 Stock
Option Plan"), the terms of which are substantially the same as the canceled
1995 Forcenergy Stock Option Plan. Under the 1999 Stock Option Plan, options to
purchase 3,000,000 shares of New Common Stock are available for issuance.
Effective February 15, 2000, options to purchase approximately 1,328,000 shares
of New Common Stock were issued and outstanding, with an exercise price of $10
per share.
EMPLOYEE STOCK PURCHASE PLAN
On February 15, 2000 the Company adopted the Forcenergy Inc 1999 Employee
Stock Purchase Plan (the "Stock Purchase Plan") the terms of which are
substantially the same as the previous employee stock purchase plan which was
canceled on February 15, 2000 in conjunction with the Reorganization (See Notes
1 and 2). Up to 480,000 shares of New Common Stock are available to be sold to
participants under terms of the Stock Purchase Plan. The Stock Purchase Plan
permits full-time Company employees, or part-time employees meeting certain
criteria, to purchase New Common Stock at a small discount from fair market
value through payroll deductions.
F-18
<PAGE> 44
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 9 -- EARNINGS PER SHARE
The following reconciles the numerators and denominators of the basic and
diluted EPS computations (in thousands, except per share data):
<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 and 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 of which were cancelled at the option of the counterparties subsequent to
the Company's bankruptcy filing. The Company received $5.5 million (fair market
value of the contracts) in cash in April 1999, in final settlement of the
contracts. The settlements were included in oil and gas sales in the
Consolidated Statements of Operations for the year ended December 31, 1999.
F-19
<PAGE> 45
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company subsequently entered into several new financial hedging
contracts ("Swaps") with respect to its future oil and natural gas production.
Under these agreements, monthly settlements are based on the differences between
the prices specified in the instrument and/or the settlement price of certain
oil and gas futures contracts quoted on the New York Mercantile Exchange
("NYMEX"). In instances where the applicable settlement price is less than the
price specified in the contract, the Company receives a settlement based on the
difference and in instances where the applicable settlement price is higher than
the specified prices, the Company pays an amount based on the difference. Swap
contracts in place at December 31, 1999 and including contracts entered into
after year-end on future oil production were as follows:
<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 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 on future natural gas
production were as follows:
<TABLE>
<CAPTION>
WEIGHTED AVERAGE
VOLUME IN NYMEX
Mcf 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-20
<PAGE> 46
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In June 1998 the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("Statement No. 133"). The statement
requires companies to report the fair market value of derivatives on the balance
sheet and record in income or other comprehensive income, as appropriate, any
changes in the fair value of the derivative. Statement No. 133 will become
effective with respect to the Company on January 1, 2001. The Company is
currently evaluating the impact of the statement.
NOTE 11 -- LEASES
The following is a schedule, by calendar year, of future minimum rental
payments, covering primarily office space, required under operating leases with
a term in excess of one year:
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
2000........................................................ $1,444
2001........................................................ 1,397
2002........................................................ 1,000
2003........................................................ 164
------
Total............................................. $4,005
======
</TABLE>
Total rental expense for operating leases were approximately $1.6 million,
$2.0 million and $1.8 million for the years ended December 31, 1999, 1998 and
1997, respectively.
NOTE 12 -- COMMITMENTS AND CONTINGENCIES
The Company is involved in various litigation matters arising in the normal
course of business. Management's assessment is that none of these matters are
anticipated to have a material adverse affect on the financial position or
results of operations of the Company.
NOTE 13 -- SIGNIFICANT CUSTOMERS
The following table reflects sales to oil and gas purchasers who
individually accounted for more than 10% of the Company's total oil and gas
revenues in a given year (in thousands):
<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.
F-21
<PAGE> 47
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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>
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:
<TABLE>
<S> <C>
Issuance of Old Common Stock................................ $98,934
Working capital acquired.................................... (4,196)
-------
Total included in oil and gas properties.......... $94,738
=======
</TABLE>
On March 31, 1998 the Company issued approximately 7.9 million shares of
Old Common Stock valued at $27 per share pursuant to the tender offer for all of
the outstanding common stock of FAB (See Note 4).
The Company paid cash interest costs, including capitalized interest, of
$14.2 million, $49.0 million, and $34.8 million for the years ended December 31,
1999, 1998 and 1997, respectively.
F-22
<PAGE> 48
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 16 -- SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
(IN THOUSANDS EXCEPT PER SHARE DATA)
--------------------------------------------------------
PREDECESSOR COMPANY
--------------------------------------------------------
1999 FIRST SECOND THIRD FOURTH ANNUAL
---- -------- ------- -------- --------- ---------
<S> <C> <C> <C> <C> <C>
Revenues............................... $ 59,738 $65,157 $ 67,598 $ 74,237 $ 266,730
Income (loss) from operations.......... $ (3,357) $ 6,048 $ 15,130 $ 27,288 $ 45,109
Net income (loss)...................... $(10,251) $ 2,626 $ 8,718 $ 108,759(1) $ 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)(2) $(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 the revaluation of assets to fair market value of $56.0 million,
gain on discharge of indebtedness of $160.0 million and reorganization costs
of $13.9 million (See Notes 1 and 2).
(2) Includes $275 million non-cash impairment of oil and gas assets recorded in
the fourth quarter of 1998 pursuant to the full cost accounting rules
mandated by the Securities and Exchange Commission ("SEC").
NOTE 17 -- SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
COST INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
Presented below are costs incurred in petroleum property acquisition,
exploration and development activities (in thousands):
<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>
F-23
<PAGE> 49
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
The following table presents total capitalized costs of proved and
unevaluated properties and accumulated depletion, depreciation and amortization
related to oil and gas producing operations (thousands):
<TABLE>
<CAPTION>
SUCCESSOR
COMPANY PREDECESSOR 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>
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.
RESERVE QUANTITIES (UNAUDITED)
Estimates of proved reserves of the Company and the related standardized
measure of discounted future net cash flow information are based on the reports
of independent petroleum engineers. All of the Company's proven reserves are
located offshore or onshore- United States. There are numerous uncertainties
inherent in estimating oil and natural gas reserves and their estimated values,
including many factors beyond the control
F-24
<PAGE> 50
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of the producer. The reserve data set forth herein represents only estimates.
Reservoir engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies and
assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and natural
gas attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected therefrom prepared by different engineers or by the same engineers at
different times may vary substantially and such reserve estimates may be subject
to downward or upward adjustment based upon such factors. Actual production,
revenues and expenditures with respect to the Company's reserves will likely
vary from estimates, and such variances may be material.
The present value of estimated future net cash flows included herein should
not be construed as the current market value of estimated oil and natural gas
reserves attributable to the Company's operations. In accordance with the
applicable requirements of the Commission, the estimated discounted net cash
flows from proved reserves are based on current prices and costs as of the date
of the estimate, whereas actual future prices and costs may be materially higher
or lower. Current prices in effect as of the valuation date incorporated the
estimated effects of hedging agreements in place (See Note 8) as of the
valuation date, and for the period the agreements will be in effect. Actual
future cash flows will also be affected by factors such as the amount and timing
of actual production, supply and demand for oil and natural gas, curtailments or
increases in consumption by purchasers and changes in governmental regulation or
taxation. The timing of actual future net cash flows from proved reserves, and
their actual present value, will be affected by the timing of both production
and the incidence of expenses in connection with development and production of
oil and gas properties. In addition, the calculation of the present value of the
future net revenues using a 10% discount as required by the Commission, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and the risk associated with the Company's reserves or
the oil and gas industry in general.
F-25
<PAGE> 51
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Predecessor Company's estimates of its proved reserves and proved
developed reserves of oil and gas as of December 31, 1997, 1998 and 1999 and the
changes in its proved reserves are as follows:
<TABLE>
<CAPTION>
LIQUIDS (1) GAS
1997 (MBbl) (MMcf)
---- ----------- -------
<S> <C> <C>
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.
F-26
<PAGE> 52
FORCENERGY INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revisions to previous estimates for the year ended December 31, 1999 were
primarily the result of higher prices as related to oil reserves and production
declines on certain properties for gas reserves. For the year ended December 31,
1998 revisions to previous estimates were primarily the result of lower prices
and the effect of those lower prices on the economic life of the properties). In
1997, an 11 million barrel price-related negative volume reduction in the
Alaskan reserves, due to a technical reduction in the economic life of the
reserves, was substantially offset by other upward revisions.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows (in thousands):
<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 income taxes...................................... (154,910) -- (52,291)
---------- ---------- ----------
Future net cash flows.................................... 1,053,091 545,987 789,552
10% annual discount for estimated timing of
cash flows............................................. (284,162) (109,298) (194,354)
---------- ---------- ----------
Standardized measure of discounted future net
cash flows............................................. $ 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-27
