<PAGE> 1
Filed pursuant to Rule 424(b)(4)
Registration No. 333-10365
PROSPECTUS
$160,000,000
[FLORES AND RUCKS,
INC. LOGO] FLORES & RUCKS, INC.
9 3/4% SENIOR SUBORDINATED NOTES DUE 2006
------------------------
Interest on the 9 3/4% Senior Subordinated Notes due 2006 (the "Notes") of
Flores & Rucks, Inc., a Delaware corporation ("F&R" or the "Company"), will be
payable semi-annually on April 1 and October 1 of each year commencing April 1,
1997. The Notes are redeemable at the option of the Company in whole or in part,
at any time on or after October 1, 2001, at the redemption prices set forth
herein, together with accrued and unpaid interest, if any, to the date of
redemption. Upon a Change of Control (as defined herein), each holder of the
Notes will have the right to require the Company to purchase all or a portion of
such holder's Notes at 101% of the aggregate principal amount thereof, together
with accrued and unpaid interest, if any, to the date of purchase. Furthermore,
under certain circumstances, the Company may become obligated to offer to
purchase all or a portion of the Notes at 100% of the principal amount thereof,
together with accrued and unpaid interest, if any, to the date of purchase with
the net proceeds of certain Asset Sales (as defined herein). See "Description of
the Notes." The net proceeds of the offering made hereby (the "Notes Offering")
will be used in part to effect the acquisition of certain oil and gas producing
fields situated primarily in the central Gulf of Mexico (the "Central Gulf
Acquisition").
Concurrent with the Notes Offering, the Selling Stockholder (as defined
herein) is offering 1,550,000 shares (1,750,000 shares if the Underwriters'
over-allotment option is exercised in full) of common stock, par value $0.01 per
share, of the Company (the "Common Stock") for sale to the public in a separate
offering (the "Common Stock Offering"). Consummation of the Notes Offering and
the Common Stock Offering are not contingent upon each other and there can be no
assurance that the Common Stock Offering will be consummated. The consummation
of the Notes Offering is contingent upon the consummation of the Central Gulf
Acquisition.
The Notes will be general unsecured senior subordinated obligations of the
Company which will be subordinated in right of payment to all existing and
future senior indebtedness of the Company, pari passu in right of payment with
all existing and future senior subordinated indebtedness of the Company and
senior in right of payment to all future subordinated indebtedness of the
Company. The Notes will be guaranteed on an unsecured senior subordinated basis
by the Company's subsidiary, Flores & Rucks, Inc., a Louisiana corporation, and
the guarantee may be released under certain circumstances. As of June 30, 1996,
on a pro forma basis after giving effect to the Notes Offering and the
application of the proceeds therefrom as described in "Use of Proceeds," the
Company and its Restricted Subsidiaries (as defined) would have had
approximately $125 million of indebtedness that effectively would rank senior to
the Notes, and no indebtedness that would be expressly subordinated to the
Notes.
The Notes will be represented by a Global Certificate registered in the name
of the nominee of The Depository Trust Company, which will act as the Depositary
(the "Depositary"). Beneficial interests in the Global Certificate will be shown
on, and transfers thereof will be effected only through, records maintained by
the Depositary and its participants. Except as described herein, Notes in
definitive form will not be issued. The Company does not intend to list the
Notes on any securities exchange. See "Risk Factors -- Absence of a Public
Market for the Notes."
SEE "RISK FACTORS" BEGINNING ON PAGE 12 FOR A DISCUSSION OF CERTAIN FACTORS
THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS IN EVALUATING AN INVESTMENT
IN THE NOTES.
------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS
THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC(1) DISCOUNT(2) COMPANY(3)
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Note................................... 99.45% 2.75% 96.7%
- -----------------------------------------------------------------------------------------------------------
Total...................................... $159,120,000 $4,400,000 $154,720,000
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
</TABLE>
(1) Plus accrued interest, if any, from September 26, 1996.
(2) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."
(3) Before deducting expenses payable by the Company estimated at $685,000.
------------------------
The Notes are being offered by the Underwriters, subject to prior sale,
when, as and if issued to and accepted by the Underwriters, subject to approval
of certain legal matters by counsel for the Underwriters and certain other
conditions. The Underwriters reserve the right to withdraw, cancel or modify
such offer and to reject orders in whole or in part. It is expected that
delivery of the Global Certificate will be made through the book-entry
facilities of the Depositary on or about September 26, 1996.
------------------------
MERRILL LYNCH & CO.
BEAR, STEARNS & CO. INC.
SALOMON BROTHERS INC
------------------------
THE DATE OF THIS PROSPECTUS IS SEPTEMBER 20, 1996.
<PAGE> 2
[MAP DEPICTING THE LOUISIANA COASTLINE AND ADJACENT GULF OF MEXICO SHOWING
THE LOCATION OF THE COMPANY'S EXISTING AND NEW PROPERTIES APPEARS HERE]
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK OR
THE NOTES OF THE COMPANY AT LEVELS ABOVE THOSE WHICH MIGHT OTHERWISE PREVAIL IN
THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK
EXCHANGE, IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF
COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
2
<PAGE> 3
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the detailed
information and financial statements and the notes thereto appearing elsewhere
in this Prospectus. Certain terms relating to the oil and gas business are
defined in the "Glossary of Certain Oil and Gas Terms" section of this
Prospectus. Unless the context indicates otherwise, references in this
Prospectus to "F&R" or the "Company" are to Flores & Rucks, Inc., a Delaware
corporation, its predecessors and their respective subsidiaries. The estimates
of the Company's proved reserves as of December 31, 1995 set forth in this
Prospectus are based on the report of Netherland, Sewell & Associates, Inc.
("Netherland Sewell"). The estimates of the Company's proved reserves as of June
30, 1996 and pro forma proved reserves for the Central Gulf Acquisition as of
June 30, 1996 set forth in this Prospectus were prepared by the Company.
This Prospectus contains certain forward-looking statements with respect to
the business of the Company and the industry in which it operates. These
forward-looking statements are subject to certain risks and uncertainties which
may cause actual results to differ significantly from such forward-looking
statements. See "Risk Factors."
THE COMPANY
The Company is an independent energy company engaged in the exploration,
development, acquisition and production of crude oil and natural gas with
operations focused primarily on the coastal onshore and shallow water offshore
regions of Louisiana (the "Louisiana Gulf"), one of the most prolific oil and
gas producing regions in the United States. As of June 30, 1996, the Company had
estimated proved reserves of approximately 36.7 MMBbls of oil and 44.1 Bcf of
natural gas, or an aggregate of approximately 44.0 MMBOE, with a Present Value
of Future Net Revenues of approximately $279.0 million and a Standardized
Measure of Discounted Future Net Cash Flows of approximately $238.2 million. On
a BOE basis, approximately 83% of the Company's proved reserves on such date
were oil. Virtually all of the Company's existing proved reserves are
attributable to Company operated wells or leases and approximately 89% of these
reserves were classified as proved developed at June 30, 1996.
The Company has focused on opportunities to acquire and develop properties
in the Louisiana Gulf. The Louisiana Gulf encompasses the Mississippi River
deltaic region (both offshore and onshore), which is the second largest
producing deltaic region in the world, with cumulative historical production of
over 21 billion BOE. A substantial number of the oil and gas fields in this
region have extensive production histories, and the Company believes that many
of these properties may possess substantial remaining reserves and significant
additional development, exploitation and exploration opportunities. The
Company's objective is to take advantage of these opportunities through the
application of recent advances in seismic and other exploration technologies
combined with maintaining an operating cost advantage as an independent
operator.
The Company's primary operations are currently located offshore in the
Mississippi River deltaic region and consist of the Main Pass 69 field ("Main
Pass 69"), the South Pass 24 and South Pass 27 fields (the "East Bay Fields")
and related production, compression and storage facilities (the "East Bay
Facilities" and together with the East Bay Fields, the "East Bay Complex"). Main
Pass 69 and the East Bay Fields are three of the top 20 fields in the Gulf of
Mexico based on total historical production. Main Pass 69 consists of 67
producing wells located on 16,058 gross (14,177 net) acres in state waters 70
miles southeast of New Orleans, Louisiana. The East Bay Fields consist of 428
producing wells located on 31,598 gross (31,579 net) acres in Plaquemines
Parish, Louisiana and adjacent federal waters. The Company's fields include a
total of 72 known producing horizons with over 700 known oil and gas reservoirs,
providing significant opportunities to enhance current production and ultimate
reserve recoveries through development and exploratory drilling, recompletions,
and in-fill and horizontal drilling. Primarily by capitalizing on these
opportunities, the Company has increased its average daily production by 59%
from 15,047 BOE for the year ended December 31, 1994 to 23,862 BOE for the
twelve months ended June 30, 1996. Since August 1, 1996, the Company's average
daily production has exceeded 30,000 BOE.
3
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The East Bay Facilities serve as a support base for the East Bay Fields.
One of the largest production complexes in the Louisiana Gulf, the East Bay
Facilities include oil processing facilities with a capacity of 70 MBbls per day
and gas compression and dehydration facilities with a capacity of 240 MMcf per
day. The East Bay Facilities, which are currently operating at approximately 30%
of processing capacity, provide a centralized operations hub with capacity
available to support expanded production through the Company's exploration,
development and acquisition programs. Management believes that any such
increased operations can be achieved with substantial economies of scale through
higher utilization of this fixed asset base.
The Company has recently extended its operations in the Louisiana Gulf to
include several coastal onshore exploration projects and believes this region
has been underexplored due to its complex geology and lack of 3-D seismic data.
Advances in 3-D seismic acquisition techniques over the past few years have led
the Company to purchase options to conduct a 3-D seismic survey and explore for
oil and gas on 26,945 acres in eastern Cameron Parish, Louisiana on its Mallard
Bay prospect area ("Mallard Bay"). The Company is currently conducting a 70
square mile proprietary 3-D seismic survey on Mallard Bay along with its 50%
working interest partner, Mobil Oil Exploration and Producing Southeast Inc.
("Mobil"). Over 70 prospects or leads have been identified at Mallard Bay from
review of 2-D seismic and subsurface data. Separately, the Company recently
acquired seismic and lease options covering 14,060 acres in its Lacassine Refuge
prospect area ("Lacassine") located approximately 6 miles northwest of Mallard
Bay which it expects to develop in 1997.
RECENT DEVELOPMENTS
On July 10, 1996, the Company entered into a Purchase and Sale Agreement
with Mobil to acquire interests in certain oil and gas producing fields and
related production facilities (the "Central Gulf Properties") primarily situated
in the shallow waters of the Central Gulf of Mexico, offshore Louisiana, for an
anticipated net purchase price of approximately $117 million (subject to
reduction to as low as $113 million if certain preferential purchase rights of
third parties on portions of the properties are exercised) (the "Central Gulf
Acquisition"). Subject to assignment of the applicable operating agreements, the
Company anticipates that it will become the operator of approximately 75% of the
properties. As of June 30, 1996, the Central Gulf Properties had estimated
proved reserves of approximately 13.8 MMBbls of oil and 50.8 Bcf of natural gas,
or an aggregate of approximately 22.3 MMBOE, with a Present Value of Future Net
Revenues of approximately $147.0 million and a Standardized Measure of
Discounted Future Net Cash Flows of approximately $113.4 million. For the six
months ended June 30, 1996, estimated average net daily production on the
Central Gulf Properties was approximately 4,800 Bbls of oil and 27,500 Mcf of
natural gas from approximately 125 producing wells on 87,514 gross (49,248 net)
acres. Pro forma for the Central Gulf Acquisition, the Company's average daily
production is expected to increase by approximately 30%, and its proved reserve
mix is expected to shift to approximately 76% oil and 24% gas from the current
mix of 83% oil and 17% gas. The closing of the Central Gulf Acquisition is
expected to occur concurrently with the consummation of the Notes Offering,
subject to approvals by the management and Board of Directors of Mobil and the
Company, and subject to the aforementioned preferential purchase rights.
The Central Gulf Acquisition will allow the Company to significantly expand
its primary operations by establishing a new core area in the central Louisiana
Gulf region while acquiring properties which it believes are complementary to
its existing asset base. The Central Gulf Properties represent a large acreage
acquisition in proximity to properties with prolific production histories. The
Company believes the Central Gulf Properties have substantial similarities with
its existing Main Pass and East Bay Fields, including a significant proven
reserve base with large exploitation and exploration potential resulting from
the Company's utilization of recently acquired 3-D seismic data. The Company
therefore expects to maximize the value of the Central Gulf Properties by
utilizing exploration, exploitation and development techniques similar to those
employed on its existing properties. The Company has already identified over 150
drilling prospects on the Central Gulf Properties that it intends to pursue.
Also, the Company believes that it will be able to integrate the Central Gulf
Properties into its existing corporate infrastructure, which should result in
future economies of scale and enhanced cash flow.
4
<PAGE> 5
STRENGTHS
The Company believes it has unique strengths that position it to continue
as a successful independent operator in the Louisiana Gulf, including the
following:
Quality of existing operations. The East Bay Fields and Main Pass 69 are
three of the 20 most productive fields in the Gulf of Mexico based on total
historical production. These fields have extensive production histories and
contain significant reserve and production enhancement opportunities. Production
from the East Bay Fields and Main Pass 69 has been predominantly from the upper
10,000 feet of sediment. While cumulative historical production from these
horizons has exceeded one billion BOE, the Company believes that potential may
exist for additional reserves to be found at these horizons, as well as deeper
horizons. As of August 9, 1996, the Company's existing properties collectively
comprised over 63,982 net acres of Louisiana state and federal offshore leases
(42,248 of which are held by production), including 15,707 net lease acres which
were acquired by the Company during the first six months of 1996 for exploratory
purposes, a large portion of which are adjacent to its producing leases.
Extensive technological database. As of August 8, 1996, the Company owned
approximately 516 square miles of 3-D seismic data and over 20,000 linear miles
of 2-D seismic data in and around its core properties. In addition, the Company
is nearing completion of a 70 square mile 3-D seismic survey covering Main Pass
69 as well as a 70 square mile survey covering Mallard Bay. These surveys are
expected to be completed by the end of September, 1996. Additionally, to
complement the Central Gulf Acquisition, the Company has acquired approximately
191 square miles of 3-D seismic data covering the Central Gulf Properties and
surrounding acreage. F&R uses state-of-the-art seismic evaluation technology in
its exploitation and exploration activities in order to reduce risks and lower
drilling costs. The seismic evaluation technology is integrated with subsurface
data to improve the Company's ability to properly define the structural and
stratigraphic features which potentially contain accumulations of hydrocarbons.
The Company employs 19 geoscientists to integrate and evaluate its expansive
seismic data base. Management believes the availability of 3-D seismic coverage
for the Gulf of Mexico at reasonable costs enhances the potential for returns on
exploration and development activities in the area.
Efficient operator. The Company is a 100% working interest owner and
operator of virtually all of its existing wells, allowing it to control
expenses, capital allocation and the timing of development and exploitation of
its fields. Since 1992, the Company has decreased lease operating expenses by
28%, from $5.45 per BOE for the period from inception (April 20, 1992) through
December 31, 1992 to $3.95 per BOE for the six months ended June 30, 1996. Prior
to the Company's ownership, lease operating expenses at the East Bay Complex in
1989, 1990, and 1991 were $8.15, $10.58, and $9.74, respectively, per BOE and
lease operating expenses at Main Pass 69 in 1989, 1990 and 1991 were $6.59,
$11.33 and $8.17, respectively, per BOE.
Expertise in the Louisiana Gulf. Management believes the Company's
existing asset base and personnel provide it with competitive advantages for
operating in the Louisiana Gulf. The Company's senior operating personnel as
well as its 19 geoscientists and 17 petroleum engineers have substantial
experience, largely through tenure at major oil companies, in the technical
challenges arising from exploitation and exploration of this region. The Company
has also assembled a team of field personnel, most with over 15 years of
experience in operating the East Bay Complex, Main Pass 69 or other large
properties in the Louisiana Gulf. Management has extensive experience and good
working relationships with federal, state and local regulatory agencies in this
region.
Expandable base of operations. The Company has additional capacity
available at its East Bay Complex and Main Pass 69 production facilities, which
can provide a foundation for further acquisition, exploitation and exploration
in the Louisiana Gulf to achieve additional production at relatively low
incremental costs. Because of the strategic location of the East Bay Facilities
between extensive offshore production and onshore processing and transmission
facilities, the excess capacity can also be used to provide services to third
parties operating in the area. The Company also believes that its operating and
administrative personnel and systems can efficiently manage the addition of
producing properties and related operations through geographic concentration,
technical expertise and economies of scale based on existing infrastructure and
the maintenance of low overhead costs.
5
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BUSINESS STRATEGY
The Company's strategy is to increase value by increasing its reserve base
and by continuing to decrease unit costs. The Company intends to grow its oil
and gas reserves by capitalizing on its strengths through the exploitation of
its existing properties, the exploration for new oil and gas reserves on its
existing properties and elsewhere and the acquisition of additional properties
with exploitation and exploration potential. The Company intends to decrease
unit costs by streamlining existing operations and increasing production. The
Company is implementing this strategy by:
Continuing development and exploitation of existing properties. The
Company is actively pursuing the development of its existing properties to fully
exploit its reserves through recompletions, horizontal and development drilling,
waterfloods and 3-D seismic enhanced exploitation drilling. F&R uses advanced
technology in its exploitation and exploration activities in order to reduce
risks and lower costs. Further, the Company seeks to drill wells with multiple
pay objectives, allowing it to reduce the risk of exploring deeper prospects by
attempting to exploit shallow reservoirs in the same well. Primarily as a result
of its development and exploitation drilling success, the Company has increased
its average daily production by 59% from 15,047 BOE for the year ended December
31, 1994 to 23,862 BOE for the twelve months ended June 30, 1996. Since August
1, 1996, the Company's average daily production has exceeded 30,000 BOE. The
Company currently has an inventory of over 330 reserve and production
enhancement projects on its existing properties. In light of these projects, the
Company plans to increase its development and exploitation drilling capital
expenditures from approximately $22 million in 1994 and $42 million in 1995 to a
budgeted amount of approximately $66 million for 1996.
Expanding exploration program. The Company is expanding its exploration
program in the Louisiana Gulf which is designed to provide exposure to selected
higher risk, higher potential rate of return prospects. The Company expects to
increase its exploratory drilling expenditures from approximately $12 million in
1995 (22% of an approximate $55 million drilling budget) to approximately $26
million in 1996 (28% of an approximate $92 million drilling budget), with
further increases possible. In order to reduce exploration risk, the Company
will apply state-of-the-art technology to identify prospects and, where
possible, select well locations with multiple pay objectives. The Company
believes the seismic database and operating experience derived from its existing
properties provide it with a competitive advantage in evaluating new prospects
on properties sharing the same or similar geologic characteristics. The Company
utilizes these assets and its experience to identify and acquire new leasehold
acreage and existing producing properties that it believes contain significant
exploration potential. In the first six months of 1996, the Company acquired
42,651 net acres of seismic options and oil and gas leases, a large portion of
which are located adjacent to its producing leases, including seismic and lease
options covering 26,945 acres in Cameron Parish. Based upon preliminary
evaluation of seismic data prior to acquisition of these leases and options, the
Company believes it has significantly enhanced its inventory of prospects.
Pursuing strategic acquisitions. The Company is continually evaluating
opportunities to acquire producing properties which may possess, among others,
one or more of the following characteristics: (i) potential for increases in
reserves and production through exploration and exploitation drilling, (ii)
proximity to the Company's existing operations, or (iii) potential opportunities
to reduce expenses through more efficient operations. While the Company focuses
primarily on the acquisition of producing properties involving large acreage
positions, it evaluates a broad range of potential transactions. Company
personnel have substantial training, experience, and an in-depth knowledge of
the Louisiana Gulf area, as well as established relationships with a number of
major and large independent energy companies operating in this region. These
factors, in combination with state-of-the-art geological and engineering
technology, assist in identifying properties that meet the Company's acquisition
objectives.
6
<PAGE> 7
THE NOTES OFFERING
Securities Offered......... $160,000,000 principal amount of 9 3/4% Senior
Subordinated Notes due 2006.
Maturity Date.............. October 1, 2006.
Interest Payment Dates..... Interest on the Notes will be payable semi-annually
in arrears on April 1 and October 1 of each year,
commencing April 1, 1997.
Optional Redemption........ The Notes will be redeemable at the option of the
Company, in whole or in part, at any time on or
after October 1, 2001 at the redemption prices set
forth herein, together with accrued and unpaid
interest, if any, to the date of redemption.
Guarantee.................. The Notes will be initially guaranteed (the
"Subsidiary Guarantee") by Flores & Rucks, Inc., a
Louisiana corporation (the "Subsidiary Guarantor"),
the sole operating subsidiary of the Company. The
Subsidiary Guarantee will be a general unsecured
senior subordinated obligation of the Subsidiary
Guarantor and will be subordinated in right of
payment to all existing or future senior
indebtedness of the Subsidiary Guarantor, pari
passu with all existing and future senior
subordinated indebtedness of the Subsidiary
Guarantor, and senior in right of payment to all
future subordinated indebtedness of the Subsidiary
Guarantor. The Subsidiary Guarantee may be released
under certain circumstances. See "Description of
the Notes -- Subsidiary Guarantees of Notes." The
Subsidiary Guarantee is limited to the extent of
any payment that would constitute a fraudulent
transfer or conveyance under federal or state law.
See "Risk Factors -- Fraudulent Conveyance
Considerations Relating to Subsidiary Guarantee"
and "Description of the Notes -- Subsidiary
Guarantees of Notes."
Certain Covenants.......... The Indenture pursuant to which the Notes will be
issued (the "Indenture") will contain certain
covenants, including, without limitation, covenants
with respect to the following matters: (i)
limitation on indebtedness; (ii) limitation on
restricted payments; (iii) limitation on issuances
and sales of restricted subsidiary stock; (iv)
limitation on transactions with affiliates; (v)
limitation on liens; (vi) disposition of proceeds
of asset sales; (vii) limitation on guarantees of
indebtedness by subsidiaries; (viii) limitation on
dividends and other payment restrictions affecting
subsidiaries; and (ix) limitation of mergers,
consolidations and transfers of assets. See
"Description of the Notes -- Certain Covenants."
Mandatory Offers to
Purchase................... Upon a Change of Control, each holder of the Notes
may require the Company to purchase all or a
portion of such holder's Notes at a purchase price
equal to 101% of the principal amount thereof,
together with accrued and unpaid interest, if any,
to the date of purchase. See "Description of the
Notes -- Certain Definitions." In the event of
certain asset dispositions, the Company will be
required to make an offer to purchase the Notes at
100% of the principal amount thereof, together with
accrued and unpaid interest, if any, to the date of
purchase. See "Description of the Notes -- Certain
Covenants -- Change of Control" and "-- Limitation
on Disposition of Proceeds of Asset Sales."
Ranking.................... The Notes will be general unsecured senior
subordinated obligations of the Company which will
be subordinated in right of payment to all existing
or future senior indebtedness of the Company, pari
passu with
7
<PAGE> 8
all existing and future senior subordinated
indebtedness of the Company, and senior in right of
payment to all future subordinated indebtedness of
the Company. As of June 30, 1996, on a pro forma
basis after giving effect to the Notes Offering,
the Company and its Restricted Subsidiaries would
have had approximately $125 million of indebtedness
that effectively would rank senior to the Notes.
Subject to certain limitations set forth in the
Indenture, the Company and its subsidiaries may
incur additional Indebtedness. See
"Capitalization," "Description of the Notes" and
"Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity
and Capital Resources."
Use of Proceeds............ The net proceeds to the Company from the Notes
Offering will be used to complete the Central Gulf
Acquisition and for general corporate purposes,
including for working capital, or to repay
outstanding indebtedness under the Company's
revolving credit facility (the "Revolving Credit
Facility"). See "Use of Proceeds."
Absence of a Public Market
for the Notes.............. There is no existing market for the Notes and there
can be no assurance as to the liquidity of any
markets that may develop for the Notes, the ability
of holders of the Notes to sell their Notes or the
price at which holders would be able to sell their
Notes. Future trading prices of the Notes will
depend on many factors, including, among other
things, prevailing interest rates, the Company's
operating results and the market for similar
securities. The Company has been advised by the
Underwriters that, subject to applicable laws and
regulations, such firms currently intend to make a
market in the Notes after the consummation of the
Notes Offering, although they are not obligated to
do so and may discontinue any market-making
activities with respect to the Notes at any time
without notice. The Company does not intend to
apply for listing of the Notes on any securities
exchange. See "Underwriting."
Common Stock Offering...... Concurrent with the Notes Offering, the Selling
Stockholder is offering 1,550,000 shares (1,750,000
shares if the Underwriters' over-allotment option
is exercised in full) of Common Stock for sale to
the public. The Company will not receive any
proceeds from the sale of Common Stock by the
Selling Stockholder in the Common Stock Offering.
The consummation of the Notes Offering and the
Common Stock Offering are not contingent upon each
other and there can be no assurance that the Common
Stock Offering will be consummated or if so on what
terms.
RISK FACTORS
An investment in the Notes involves certain risks that a potential investor
should carefully evaluate prior to making such an investment. See "Risk
Factors."
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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The summary historical financial data set forth below for the years ended
December 31, 1993, 1994 and 1995 for the Company have been derived from the
audited financial statements and notes thereto contained elsewhere in this
Prospectus. The financial data for the six months ended June 30, 1995 and 1996
are derived from unaudited financial statements of the Company. The unaudited
pro forma balance sheet data as of June 30, 1996 gives effect to the Notes
Offering and the Central Gulf Acquisition as if they had occurred on June 30,
1996. The unaudited pro forma statements of operations data for the year ended
December 31, 1995 and for the six months ended June 30, 1996, give effect to the
Notes Offering, the Central Gulf Acquisition and the March 1996 public offering
of shares of Common Stock by the Company as if they had occurred on January 1,
1995. The summary historical and pro forma financial data are qualified in their
entirety by, and should be read in conjunction with the "Unaudited Pro Forma
Consolidated Financial Statements," "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the financial statements and
the notes thereto included elsewhere in this Prospectus. For additional
information relating to the Company's operations, see "Business and Properties."
<TABLE>
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YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, JUNE 30,
------------------------------------------- -----------------------------
PRO FORMA PRO FORMA
1993 1994 1995 1995 1995 1996 1996
-------- --------- -------- --------- ------- ------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS AND OTHER FINANCIAL
AND OPERATING DATA:
REVENUES & EXPENSE DATA:
Revenues..................................... $ 47,483 $ 75,395 $127,970 $176,722 $55,872 $69,082 $100,708
Direct Operating Expenses.................... 19,201 30,324 40,047 52,924 18,970 22,044 27,345
General & Administrative Expenses............ 5,032 10,351 11,312 11,762 5,613 6,025 6,250
Depreciation, Depletion & Amortization....... 20,140 36,459 54,084 77,671 23,167 28,973 40,608
Interest Expense............................. 1,055 4,507 17,620 26,406 8,493 8,188 13,084
Loss on Production Payment Repurchase and
Refinancing(1)............................. -- 16,681 -- -- -- -- --
Net Income (Loss) Before Income Tax Expense
(Benefit).................................. 2,227 (22,179) 5,210 8,262 (251) 3,850 13,420
Income Tax Expense (Benefit)(2).............. -- -- (4,692) (3,517 ) -- 1,514 5,199
Net Income (Loss)............................ 2,227 (22,179) 9,902 11,779 (251) 2,336 8,221
Earnings (Loss) per Common Share(3).......... -- -- 0.66 0.78 (0.02) 0.13 0.46
OTHER FINANCIAL DATA:
EBITDA(4).................................... $ 23,422 $ 35,855 $ 77,645 $113,070 $31,684 $43,468 $ 69,569
Net Cash Provided By (Used In) Operating
Activities(5).............................. 103,112 (115,485) 58,880 -- 40,642 47,260 --
Capital Expenditures(6)...................... 123,600 74,477 73,652 -- 44,770 64,771 --
Ratio of EBITDA to Interest Expense(4)....... -- -- 4.4x 4.3 x 3.7x 5.3x 5.3 x
OPERATING DATA:
Sales Volumes:
Oil (MBbl)................................. 2,850 4,286 6,057 7,873 2,630 3,008 3,882
Gas (MMcf)................................. 3,704 7,234 12,393 22,280 5,619 7,016 12,021
MBOE....................................... 3,467 5,492 8,123 11,586 3,567 4,178 5,886
Average Prices(7):
Oil (per Bbl).............................. $ 13.82 $ 14.24 $ 17.39 $ 17.49 $ 17.77 $ 19.80 $ 20.03
Gas (per Mcf).............................. 1.81 1.76 1.82 1.75 1.72 2.86 2.78
BOE (per BOE).............................. 13.30 13.42 15.75 15.25 15.81 19.05 18.90
Lease Operating Expenses (per BOE)........... $ 4.10 $ 4.29 $ 3.70 $ 3.70 $ 3.99 $ 3.95 $ 3.71
</TABLE>
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
-----------------------------
HISTORICAL PRO FORMA
---------- --------------
<S> <C> <C>
BALANCE SHEET DATA:
Oil and Gas Assets, Net.............................................................. $216,380 $333,180
Total Assets......................................................................... 256,721 412,841
Long-Term Debt....................................................................... 128,160 284,280
Stockholders' Equity................................................................. 84,452 84,452
</TABLE>
9
<PAGE> 10
- ---------------
(1) The amount shown for the year ended December 31, 1994 represents primarily
the excess of the purchase price of nonrecourse volumetric production
payment interests (the "Production Payments") over the book value of the
Production Payments liability as of December 7, 1994.
(2) The Company was formed as an S corporation under the Internal Revenue Code
and, as such, all income taxes were the obligation of the Company's
stockholders. Therefore, through the date of the Company's initial public
offerings (the "Initial Offerings") (December 7, 1994), no historical
federal or state income tax expense has been provided for in the financial
statements. In conjunction with the Initial Offerings, the Company
converted to a C corporation under the Internal Revenue Code. The Company
recorded a deferred tax asset of $6.3 million, offset by a valuation
allowance of $6.3 million at December 31, 1994 and a deferred tax asset of
$4.7 million at December 31, 1995. As a result of the reversal of the
valuation allowance, the Company recorded a net income tax benefit of $4.7
million in the year ended December 31, 1995.
(3) If the Company had recognized a tax provision at statutory rates for the
year ended December 31, 1995, rather than an income tax benefit, historical
earnings per common share would have been $0.22 for such period. Earnings
per share has not been presented for periods prior to or including the date
of the Initial Offerings, as these amounts would not be meaningful or
indicative of the ongoing entity.
(4) Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDA has not been reduced for the recognition of noncash revenues
associated with the Production Payments. EBITDA is not intended to
represent cash flow in accordance with generally accepted accounting
principles and does not represent the measure of cash available for
distribution. EBITDA is not intended as an alternative to earnings from
continuing operations or net income.
(5) Cash flow from operating activities in 1993 includes $95.7 million from the
sale of the Production Payments. Cash flow from operating activities for
the year ended December 31, 1994 was reduced by $123.6 million related to
the repurchase of the Production Payments.
(6) Includes $115.5 million in the year ended December 31, 1993 related to the
acquisition of the East Bay Complex.
(7) Excludes results of hedging activities which increased (decreased) revenue
recognized in the years ended December 31, 1993, 1994 and 1995 by $1.2
million, $1.7 million and $(0.5) million, respectively. Including the
effect of hedging activities, the Company's average oil price per Bbl
received was $14.23, $14.56 and $17.27 in the years ended December 31,
1993, 1994 and 1995, respectively, and the average gas price per Mcf
received was $1.81 and $1.84 in the years ended December 31, 1994 and 1995,
respectively. The Company did not enter into any hedging activities
relating to gas during 1993. Hedging activities decreased revenue
recognized in the six months ended June 30, 1995 and 1996 by $1.0 million
and $10.5 million, respectively. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $17.32 and
$17.92 in the six months ended June 30, 1995 and 1996, respectively, and
the average gas price per Mcf received was $1.75 and $2.17 in the six
months ended June 30, 1995 and 1996, respectively.
10
<PAGE> 11
SUMMARY HISTORICAL AND PRO FORMA RESERVE INFORMATION
The following tables set forth information with respect to the Company's
proved reserves as of December 31, 1995, as estimated by Netherland Sewell,
independent petroleum engineers for the Company. The information with respect to
the proved reserves of the Company and the Central Gulf Properties as of June
30, 1996 have been estimated by the Company. The pro forma combined reserve
information gives pro forma effect to the consummation of the Central Gulf
Acquisition as of June 30, 1996. See "Summary -- Recent Developments" for a
description of the Central Gulf Acquisition. As of December 31, 1995 and June
30, 1996, the average sales prices used for purposes of estimating the Company's
proved reserves, the future net revenues therefrom and present value of such
future net revenues were $2.56 and $2.59 per Mcf of gas and $18.94 and $19.74
per Bbl of oil, respectively (excluding the effect of net price hedging
positions). For additional information relating to the Company's reserves, see
"Risk Factors -- Reliance on Estimates of Proved Reserves," "Business and
Properties -- Oil and Natural Gas Reserves" and Note 15 to the Company's
consolidated financial statements.
<TABLE>
<CAPTION>
JUNE 30, 1996
PROVED RESERVES(1)
---------------------------------------------------------------------------------------
CENTRAL CENTRAL CENTRAL
GULF GULF GULF PRO
COMPANY COMPANY COMPANY PROPERTIES PROPERTIES PROPERTIES FORMA
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL COMBINED(3)
--------- ----------- -------- --------- ----------- ---------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Net Proved Reserves:
Oil (MBbls)........................ 32,463 4,233 36,696 9,148 4,659 13,807 50,503
Gas (MMcf)......................... 41,397 2,681 44,078 31,462 19,345 50,807 94,885
MBOE (6 Mcf per Bbl)............... 39,362 4,680 44,042 14,392 7,883 22,275 66,317
Estimated Future Net Revenues (Before
Income Taxes)...................... $306,082 $36,996 $343,078 $103,993 $86,966 $190,959 $ 534,037
Present Value of Future Net Revenues
(Before Income Taxes; Discounted at
10%)............................... $251,515 $27,508 $279,023 $ 89,773 $57,265 $147,038 $ 426,061
Standardized Measure of Discounted
Future Net Cash Flows(2)........... $238,161 $113,370 $ 351,531
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, 1995
PROVED RESERVES(4)
--------------------------------------
COMPANY COMPANY COMPANY
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Net Proved Reserves:
Oil (MBbls)................................................................ 31,702 2,127 33,829
Gas (MMcf)................................................................. 48,635 1,941 50,576
MBOE (6 Mcf per Bbl)....................................................... 39,807 2,451 42,258
Estimated Future Net Revenues (Before Income Taxes).......................... $261,848 $17,982 $279,830
Present Value of Future Net Revenues (Before Income Taxes; Discounted at
10%)....................................................................... $223,880 $10,855 $234,735
Standardized Measure of Discounted Future Net Cash Flows(2).................. $203,940
</TABLE>
- ---------------
(1) The reserve information as of June 30, 1996 was prepared by the Company's
engineers in accordance with the rules and regulations of the Securities and
Exchange Commission (the "Commission"); however, such reserve information
has not been reviewed by independent reserve engineers. In accordance with
rules and regulations of the Commission, the pre-tax estimated future net
revenues, pre-tax present value of future net revenues and the Standardized
Measure of Discounted Future Net Cash Flows for the Company have been
decreased by approximately $7,595,000, $6,861,000 and $4,596,000,
respectively, representing the effect of hedging transactions entered into
as of June 30, 1996.
(2) The Standardized Measure of Discounted Future Net Cash Flows prepared by the
Company represents the Present Value of Future Net Revenues after income
taxes discounted at 10%.
(3) If the preferential purchase rights with respect to the Central Gulf
Acquisition are exercised in full the pro forma net proved reserves, the
Present Value of Future Net Revenues and the Standardized Measure of
Discounted Future Net Cash Flows would be 65,333 MBOE, $421,006,000 and
$347,219,000, respectively.
(4) In accordance with rules and regulations of the Commission, the pre-tax
estimated future net revenues, pre-tax present value of future net revenues
and the Standardized Measure of Discounted Future Net Cash Flows prepared by
the Company have been decreased by approximately $7,669,000, $7,181,000 and
$4,929,000, respectively, representing the effect of hedging transactions
entered into as of December 31, 1995.
11
<PAGE> 12
RISK FACTORS
An investment in the Company involves a significant degree of risk.
Prospective purchasers should give careful consideration to the specific factors
set forth below, as well as the other information set forth in this Prospectus,
before purchasing the securities offered hereby.
When used in this Prospectus, the words "anticipate," "estimate," "project"
and similar expressions are intended to identify forward-looking statements.
Such statements are subject to certain risks, uncertainties and assumptions.
Should one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual results may vary materially from
those anticipated, estimated or projected. Among the key factors that have a
direct bearing on the Company's results of operations and the industry in which
it operates are fluctuations of the prices received for the Company's oil and
natural gas, uncertainty of drilling results and reserve estimates, competition
from other exploration, development and production companies, operating hazards,
abandonment costs and the effects of governmental regulation. These and other
factors are discussed below and elsewhere in this Prospectus.
REPLACEMENT OF RESERVES
The Company's future success depends upon its ability to find, develop or
acquire additional oil and gas reserves that are economically recoverable. The
proved reserves of the Company will generally decline as reserves are depleted,
except to the extent that the Company conducts successful exploration or
development activities or acquires properties containing proved reserves, or
both. In order to increase reserves and production, the Company must continue
its development and exploration drilling and recompletion programs or undertake
other replacement activities. The Company's current strategy includes increasing
its reserve base through acquisitions of producing properties and by continuing
to exploit its existing properties. There can be no assurance, however, that the
Company's planned development and exploration projects and acquisition
activities will result in significant additional reserves or that the Company
will have continuing success drilling productive wells at low finding and
development costs. Furthermore, while the Company's revenues may increase if
prevailing oil and gas prices increase significantly, the Company's finding
costs for additional reserves could also increase. For a discussion of the
Company's reserves, see "Business and Properties -- Oil and Natural Gas
Reserves."
PRICE FLUCTUATIONS AND MARKETS
The Company's results of operations are highly dependent upon the prices
received for the Company's oil and natural gas. Substantially all of the
Company's sales of oil and natural gas are made in the spot market, or pursuant
to contracts based on spot market prices and not pursuant to long-term,
fixed-price contracts. Accordingly, the prices received by the Company for its
oil and natural gas production are dependent upon numerous factors beyond the
control of the Company. These factors include, but are not limited to, the level
of consumer product demand, governmental regulations and taxes, the price and
availability of alternative fuels, the level of foreign imports of oil and
natural gas, and the overall economic environment. Any significant decline in
prices for oil and natural gas could have a material adverse effect on the
Company's financial condition, results of operations and quantities of reserves
recoverable on an economic basis. Should the industry experience significant
price declines from current levels or other adverse market conditions, the
Company may not be able to generate sufficient cash flow from operations to meet
its obligations and make planned capital expenditures. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources," "Business and Properties -- Oil
and Gas Marketing and Major Customers," and "-- Governmental Regulation."
The availability of a ready market for the Company's oil and natural gas
production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to, and the capacity
of, oil and gas gathering systems, pipelines or trucking and terminal
facilities. Wells may be shut-in for lack of a market or due to inadequacy or
unavailability of pipeline or gathering system capacity.
In order to manage its exposure to price risks in the sale of its crude oil
and natural gas, the Company from time to time enters into energy price swap
arrangements. The Company believes that its hedging
12
<PAGE> 13
strategies are generally conservative in nature. As of August 2, 1996, the
Company's net exposure relating to existing swap arrangements (the cost the
Company would be required to pay to buyout all contracts associated with its
existing swap agreements) was approximately $2.9 million. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters."
EFFECTS OF LEVERAGE
After giving pro forma effect to the Notes Offering and the application of
the net proceeds therefrom, the Company will be highly leveraged, with
outstanding long-term indebtedness of approximately $284 million as of June 30,
1996. See "Use of Proceeds." The Company's level of indebtedness has several
important effects on its future operations, including (i) a substantial portion
of the Company's cash flow from operations is dedicated to the payment of
interest on its indebtedness and is not available for other purposes, (ii) the
covenants contained in the indenture (the "Existing Indenture") related to the
Company's 13 1/2% Senior Notes due 2004 (the "Senior Notes") require the Company
to meet certain financial tests, and the Existing Indenture contains, and the
Indenture will contain, other restrictions that limit the Company's ability to
borrow additional funds or to dispose of assets and affect the Company's
flexibility in planning for, and reacting to, changes in its business, including
possible acquisition activities and (iii) the Company's ability to obtain
additional financing in the future for working capital, capital expenditures,
acquisitions, general corporate purposes or other purposes may be impaired.
Moreover, future acquisition or development activities may require the Company
to alter its capitalization significantly. See "-- Replacement of Reserves,"
"-- Substantial Capital Requirements," "Managements Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" and "Description of the Notes."
The Company is currently in compliance with all covenants contained in the
Existing Indenture and has been in compliance since the issuance of the Senior
Notes.
The Company's ability to meet its debt service obligations and to reduce
its total indebtedness will be dependent upon the Company's future performance,
which will be subject to oil and gas prices, general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. There can be no assurance that the
Company's future performance will not be adversely affected by such economic
conditions and financial, business and other factors. See "-- Price Fluctuations
and Markets" and "Capitalization."
DRILLING RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells, but from
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating, and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment and services.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploration, development, production and
abandonment of its oil and natural gas reserves. The Company intends to finance
such capital expenditures primarily with funds provided by operations and
borrowings under the Revolving Credit Facility. The Company increased direct
capital expenditures from approximately $35 million in fiscal 1994 (excluding
acquisitions) to approximately $69 million in 1995. The Company has budgeted
$124 million for direct capital expenditures in 1996.
The Company believes that, after debt service, it will have sufficient cash
provided by operating activities and availability under the Revolving Credit
Facility to fund planned capital expenditures through 1997. If
13
<PAGE> 14
revenues decrease as a result of lower oil and gas prices or otherwise, the
Company may have limited ability to expend the capital necessary to replace its
reserves or to maintain production at current levels, resulting in a decrease in
production over time. If the Company's cash flow from operations is not
sufficient to satisfy its capital expenditure requirements, there can be no
assurance that additional debt or equity financing will be available to meet
these requirements. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
ACQUISITION RISKS
The Company constantly evaluates acquisition opportunities and frequently
engages in bidding and negotiation for acquisitions, many of which are
substantial. If successful in this process, the Company may be required to alter
or increase its capitalization substantially to finance these acquisitions
through the issuance of additional debt or equity securities, the sale of
production payments or otherwise; however, both the Revolving Credit Facility
and the Existing Indenture include, and the Indenture will include, covenants
that limit the Company's ability to incur additional indebtedness. See
"-- Effects of Leverage." These changes in capitalization may significantly
affect the risk profile of the Company or, in the case of the issuance of
additional equity securities, may be significantly dilutive to holders of Common
Stock. Additionally, significant acquisitions can change the nature of the
operations and business of the Company depending upon the character of the
acquired properties, which may be substantially different in operating or
geologic characteristics or geographic location than existing properties. While
it is the Company's current intent to concentrate on acquiring producing
properties with development and exploration potential located in the Louisiana
Gulf, there is no assurance that the Company would not pursue acquisitions of
properties located in other geographic regions. Moreover, there can be no
assurance that the Company will be successful in the acquisition of any material
property interests. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
RELIANCE ON ESTIMATES OF PROVED RESERVES
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company. The
Company's historical reserve information set forth in this Prospectus represents
estimates based on reports prepared by Netherland Sewell, as of December 31,
1995, and by the Company, as of June 30, 1996. Likewise, the pro forma reserve
information set forth in this Prospectus relating to the Central Gulf Properties
represents estimates based on reports prepared by the Company, as of June 30,
1996.
Petroleum engineering is not an exact science. Information relating to the
Company's proved oil and gas reserves is based upon engineering estimates.
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 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. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material. See "Business and
Properties -- Oil and Natural Gas Reserves."
The Present Value of Future Net Revenues referred to in this Prospectus
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net cash flows
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by factors such as the
amount and timing of actual production, supply and demand for oil and gas,
curtailments or increases in consumption by gas purchasers and changes in
governmental regulations or taxation. The timing
14
<PAGE> 15
of actual future net cash flows from proved reserves, and thus their actual
present value, will be affected by the timing of both the production and the
incurrence of expenses in connection with development and production of oil and
gas properties. In addition, the 10% discount factor, which is required by the
Commission to be used to calculate discounted future net cash flows for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the Company or the oil and gas industry in general.
COMPETITION
The Company operates in the highly competitive areas of oil and natural gas
exploration, development and production with other companies, many of which may
have substantially larger financial resources, staffs, and facilities. See
"Business and Properties -- Competition."
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for and production and transportation of oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which can
result in loss of hydrocarbons, environmental pollution, personal injury claims,
and other damage to properties of the Company and others. Additionally, the
Company's oil and gas operations are located in an area that is subject to
tropical weather disturbances, some of which can be severe enough to cause
substantial damage to facilities and possibly interrupt production. As
protection against operating hazards, the Company maintains insurance coverage
against some, but not all, potential losses. The Company's coverages include,
but are not limited to, operator's extra expense, physical damage on certain
assets, employer's liability, comprehensive general liability, automobile,
workers' compensation and loss of production income insurance. The Company
believes that its insurance is adequate and customary for companies of a similar
size engaged in operations similar to those of the Company, but losses could
occur for uninsurable or uninsured risks or in amounts in excess of existing
insurance coverage. The occurrence of an event that is not fully covered by
insurance could have an adverse impact on the Company's financial condition and
results of operations.
ABANDONMENT COSTS
Due to the Company's large number of offshore producing wells and expansive
production facilities, government regulations and lease terms will require the
Company to incur substantial abandonment costs. As of June 30, 1996, total
abandonment costs for the Company's existing properties estimated to be incurred
through 2008 were approximately $56 million, and total abandonment costs for the
Central Gulf Properties estimated to be incurred through 2009 were approximately
$31 million. Estimated abandonment costs have been included in determining
actual and pro forma estimates of the Company's future net revenues from proved
reserves included herein, and the Company accounts for such costs through its
provision for depreciation, depletion and amortization. Under the terms of the
acquisition agreements for the Company's existing principal producing
properties, the Company is required to fund periodically restricted cash
accounts as a reserve for abandonment costs on such properties. See "Business
and Properties -- Abandonment Costs" and Note 12 to the audited consolidated
financial statements of the Company included elsewhere herein.
COMPLIANCE WITH GOVERNMENT REGULATIONS
The Company's business is subject to certain Federal, state, and local laws
and regulations relating to the exploration for, and the development, production
and transportation of, oil and natural gas, as well as environmental and safety
matters. Many of these laws and regulations have become more stringent in recent
years, often imposing greater liability on a larger number of potentially
responsible parties. Although the Company believes it is in substantial
compliance with all applicable laws and regulations, the requirements imposed by
such laws and regulations are frequently changed and subject to interpretation,
and the Company is unable to predict the ultimate cost of compliance with these
requirements or their effect on its operations. Under certain circumstances, the
Minerals Management Service ("MMS"), an agency of the U.S. Department of the
Interior, may require any Company operations on federal leases to be suspended
or
15
<PAGE> 16
terminated. Any such suspensions, terminations or inability to meet applicable
bonding requirements could materially and adversely affect the Company's
financial condition and operations. Although significant expenditures may be
required to comply with governmental laws and regulations applicable to the
Company, to date such compliance has not had a material adverse effect on the
earnings or competitive position of the Company. It is possible that such
regulations in the future may add to the cost of operating offshore drilling
equipment or may significantly limit drilling activity. See "Business and
Properties -- Abandonment Costs," "-- Governmental Regulation" and
"-- Environmental Matters."
On August 25, 1993, the MMS published an advance notice of its intention to
adopt regulations under the Oil Pollution Act of 1990 ("OPA 90") that would
require owners and operators of offshore oil and natural gas facilities to
establish $150 million in financial responsibility in case of a potential spill.
In November 1995, the U.S. Senate approved a bill that would amend OPA 90 to
reduce the level of financial responsibility to $35 million, subject to increase
under certain circumstances. The U.S. House of Representatives passed an amended
version of the U.S. Senate bill on February 29, 1996. The measure is now before
a joint congressional conference. The Clinton Administration has expressed its
support for this legislation. The MMS has indicated that it would not move
forward with the adoption of its proposed rule until the United States Congress
has had an opportunity to act on the matter. Based on the passage of these bills
and the support of the Clinton Administration, it appears that the level of
financial responsibility required under OPA 90 will be reduced. The impact of
the regulations, however, should not be any more adverse to the Company than
they will be to other similarly situated owners or operators in the Gulf of
Mexico region.
DEPENDENCE UPON KEY PERSONNEL
The success of the Company has been and will continue to be highly
dependent on the Company's Chairman of the Board and Chief Executive Officer,
James C. Flores, and a limited number of other senior management personnel. Loss
of the services of Mr. Flores or any of those other individuals could have a
material adverse effect on the Company's operations. The Company can make no
assurance regarding the future affiliation of Mr. Flores with the Company. See
"Management."
CONTROL BY FOUNDER
James C. Flores beneficially owns an aggregate of 3,535,504 shares of
Common Stock, constituting approximately 18.1% of the outstanding shares of
Common Stock. In addition, William W. Rucks, IV (the "Selling Stockholder")
beneficially owns an aggregate of 3,463,010 shares of Common Stock, of which up
to 1,750,000 may be sold in the Common Stock Offering. Subject to the completion
of the Common Stock Offering, Mr. Rucks has granted to Mr. Flores the option to
purchase up to 1,600,000 shares of Common Stock owned by Mr. Rucks during the
three year period commencing upon consummation of the Common Stock Offering. In
connection therewith, Mr. Rucks will grant Mr. Flores an irrevocable proxy to
vote the 1,600,000 shares of Common Stock, constituting an additional 8.2% of
the Company's outstanding shares of Common Stock, during the option exercise
period and Mr. Rucks will resign as Vice Chairman and President of the Company.
Accordingly, Mr. Flores is in a position to control or influence actions that
require the consent of the Company's stockholders, including the election of
directors.
SUBORDINATION OF NOTES; HOLDING COMPANY STRUCTURE
The Indenture governing the Notes will limit, but will not prohibit, the
incurrence by the Company of additional indebtedness that is senior in right of
payment to the Notes (including by reason of structural subordination of the
Notes to the indebtedness and other liabilities of the Company's subsidiaries).
In the event of bankruptcy, liquidation, reorganization or other winding up of
the Company, the assets of the Company will be available to pay the Company's
obligations on the Notes offered hereby only after all Senior Indebtedness (as
defined) has been paid in full, and there may not be sufficient assets remaining
to pay amounts due on the Notes. In addition, under certain circumstances, no
payments may be made with respect to principal of, premium, if any, or interest
on the Notes if a default exists with respect to any Senior Indebtedness. See
"Description of Notes--Subordination."
16
<PAGE> 17
All of the Company's operating income and cash flow is generated by Flores
& Rucks, Inc., a Louisiana corporation ("FRI Louisiana"), and a wholly owned
subsidiary and Restricted Subsidiary under the Existing Indenture. As a result,
funds necessary to meet the Company's debt service obligations, including the
payment of principal and interest on the Notes, will be provided by
distributions or advances from this subsidiary. In addition, for state income
tax purposes FRI Louisiana will covenant with the Company to assume, as between
the Company and FRI Louisiana, the payment obligations under the Notes in
exchange for the advance of substantially all the net proceeds of the Notes
Offering to FRI Louisiana. Such intercompany assumption will not affect the
primary liability of the Company under the Notes.
As of June 30, 1996, on a pro forma basis after giving effect to the Notes
Offering and the application of the proceeds therefrom as described in "Use of
Proceeds," the Company and its Restricted Subsidiaries would have had
approximately $125 million of indebtedness that effectively would rank senior to
the Notes.
The Existing Indenture imposes limits on the ability of the Company and its
subsidiaries to incur additional indebtedness and liens and to enter into
agreements that would restrict the ability of such subsidiaries to make
distributions, loans or other payments to the Company. The Indenture will
contain similar provisions. However, these limitations are subject to various
qualifications. Subject to certain limitations, the Company and its subsidiaries
may incur additional secured indebtedness. For additional details of these
provisions and the applicable qualifications, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources," "Description of the Notes -- Ranking," "-- Certain
Covenants."
FRAUDULENT CONVEYANCE CONSIDERATIONS RELATING TO SUBSIDIARY GUARANTEE
The Company's obligations under the Notes will be guaranteed on an
unsecured senior subordinated basis by the Subsidiary Guarantor. Various
fraudulent conveyance laws have been enacted for the protection of creditors and
may be utilized by a court of competent jurisdiction to subordinate or avoid any
Subsidiary Guarantee issued by a Subsidiary Guarantor. It is also possible that
under certain circumstances a court could hold that the direct obligations of
the Subsidiary Guarantor could be superior to the obligations under the
Subsidiary Guarantee.
To the extent that a court were to find that (x) a Subsidiary Guarantee was
incurred by the Subsidiary Guarantor with the intent to hinder, delay or defraud
any present or future creditor or that the Subsidiary Guarantor contemplated
insolvency with a design to favor one or more creditors to the exclusion in
whole or in part of others or (y) the Subsidiary Guarantor did not receive fair
consideration or reasonably equivalent value for issuing the Subsidiary
Guarantee and, at the time it issued the Subsidiary Guarantee, the Subsidiary
Guarantor (i) was insolvent or rendered insolvent by reason of the issuance of
the Subsidiary Guarantee, (ii) was engaged or about to engage in a business or
transaction for which the remaining assets of the Subsidiary Guarantor
constituted unreasonably small capital or (iii) intended to incur, or believed
that it would incur, debts beyond its ability to pay such debts as they matured,
the court could avoid or subordinate the Subsidiary Guarantee in favor of the
Subsidiary Guarantor's other creditors. Among other things, a legal challenge of
the Subsidiary Guarantee issued by the Subsidiary Guarantor on fraudulent
conveyance grounds may focus on the benefits, if any, realized by the Subsidiary
Guarantor as a result of the issuance by the Company of the Notes. To the extent
the Subsidiary Guarantee is avoided as a fraudulent conveyance or held
unenforceable for any other reason, the holders of the Notes would cease to have
any claim in respect of such Subsidiary Guarantor and would be creditors solely
of the Company.
On the basis of financial information and other information currently
available to it, the Company believes that the Notes and the Subsidiary
Guarantee issued concurrently with the issuance of the Notes are being incurred
for proper purposes and in good faith and that, after giving effect to
indebtedness incurred in connection with the issuance of the Notes and the
issuance of the Subsidiary Guarantee, the Company and the Subsidiary Guarantor
are solvent and will continue to be solvent, will have sufficient capital for
carrying on their respective business and will be able to pay their debts as
such debts become absolute and mature. Further, since the Company will advance
all of the net proceeds from the Notes Offering to FRI Louisiana in order to
apply such proceeds to their intended uses, the Company believes that FRI
Louisiana will have
17
<PAGE> 18
received fair consideration or reasonably equivalent value for the issuance of
the Subsidiary Guarantee. There can be no assurance, however, that a court
passing on such questions would reach the same conclusions. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Description of the Notes."
ABSENCE OF A PUBLIC MARKET FOR THE NOTES
There is no existing market for the Notes and there can be no assurance as
to the liquidity of any markets that may develop for the Notes, the ability of
holders of the Notes to sell their Notes or the price at which holders would be
able to sell their Notes. Future trading prices of the Notes will depend on many
factors, including, among other things, prevailing interest rates, the Company's
operating results and the market for similar securities. The Company has been
advised by the Underwriters that, subject to applicable laws and regulations,
such firms currently intend to make a market in the Notes after the consummation
of the Notes Offering, although they are not obligated to do so and may
discontinue any market-making activities with respect to the Notes at any time
without notice. The Company does not intend to apply for listing of the Notes on
any securities exchange. See "Underwriting."
18
<PAGE> 19
THE COMPANY
The Company is a corporation organized under the laws of the State of
Delaware. The Company's principal executive offices are located at 8440
Jefferson Highway, Suite 420, Baton Rouge, Louisiana 70809, and its telephone
number is (504) 927-1450.
COMMON STOCK OFFERING
Concurrent with the Notes Offering, the Selling Stockholder is offering
1,550,000 shares of Common Stock to the public. In addition, in the Common Stock
Offering the Selling Stockholder has granted the Underwriters an option to
purchase up to 200,000 additional shares of Common Stock to cover over-
allotments. The consummation of the Notes Offering and the Common Stock Offering
are not contingent upon each other and there can be no assurance that the Common
Stock Offering will be consummated.
USE OF PROCEEDS
The net proceeds from the Notes Offering are estimated to be approximately
$154 million. Of such proceeds, up to $117 million will be used to consummate
the Central Gulf Acquisition, and the remainder will be used for general
corporate purposes, including for working capital, or to repay outstanding
indebtedness under the Revolving Credit Facility (estimated to be approximately
$30 million as of September 30, 1996). The indebtedness under the Revolving
Credit Facility was incurred for working capital purposes, bore interest at a
weighted average rate of 8.25% at June 30, 1996 and has a final maturity date of
December 31, 2000. See Note 9 of Notes to Consolidated Financial Statements.
19
<PAGE> 20
CAPITALIZATION
The following table sets forth the consolidated capitalization of the
Company as of June 30, 1996, and as adjusted to give effect to the Notes
Offering and the application of the net proceeds therefrom (assuming net
proceeds of $154 million) as described in "Use of Proceeds." The information
presented below should be read in conjunction with the consolidated financial
statements of the Company and notes thereto, "Selected Historical Financial and
Operating Data" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" included elsewhere in or incorporated by reference
into this Prospectus.
<TABLE>
<CAPTION>
JUNE 30, 1996
---------------------
AS
ACTUAL ADJUSTED
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt:
Revolving Credit Facility.......................................... $ 3,000 $ --
Senior Notes....................................................... 125,000 125,000
Notes offered hereby............................................... -- 159,120
Other long-term debt............................................... 160 160
-------- --------
Total long-term debt....................................... 128,160 284,280
Stockholders' Equity:
Preferred stock, $.01 par value, 10,000,000 shares authorized,
no shares issued and outstanding................................ -- --
Common stock, $.01 par value, 100,000,000 shares authorized,
19,555,223 shares issued and outstanding........................ 196 196
Additional paid-in capital......................................... 89,734 89,734
Retained earnings (deficit)........................................ (5,478) (5,478)
-------- --------
Total stockholders' equity................................. 84,452 84,452
-------- --------
Total capitalization....................................... $212,612 $368,732
======== ========
</TABLE>
20
<PAGE> 21
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
The selected financial data set forth below for the period from inception
(April 20, 1992) through December 31, 1992, and the years ended December 31,
1993, 1994 and 1995 for the Company are derived from the audited financial
statements and notes thereto contained elsewhere in this Prospectus. The
financial data for the six months ended June 30, 1995 and 1996 are derived from
unaudited financial statements of the Company. The selected historical financial
data are qualified in their entirety by, and should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements and the notes thereto included
elsewhere in this Prospectus. For additional information relating to the
Company's operations, see "Business and Properties."
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
---------------------------------------------------- -----------------
1991 1992 1993 1994 1995 1995 1996
-------- ------- -------- --------- -------- ------- -------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS AND OTHER FINANCIAL AND
OPERATING DATA:
REVENUES & EXPENSE DATA:
Revenues
Flores & Rucks, Inc. (1)............................ -- $13,279 $ 47,483 $ 75,395 $127,970 $55,872 $69,082
Combined Acquisitions (2)........................... $121,275 95,018 38,197 8,707 -- -- --
Direct Operating Expenses
Flores & Rucks, Inc. (1)............................ -- 6,687 19,201 30,324 40,047 18,970 22,044
Combined Acquisitions (2)........................... 72,991 40,155 13,779 4,089 -- -- --
General & Administrative Expenses..................... -- 385 5,032 10,351 11,312 5,613 6,025
Depreciation, Depletion & Amortization................ -- 3,420 20,140 36,459 54,084 23,167 28,973
Interest Expense...................................... -- 241 1,055 4,507 17,620 8,493 8,188
Loss on Production Payment Repurchase and Refinancing
(3)................................................. -- -- -- 16,681 -- -- --
Net Income (Loss) Before Income Tax Expense
(Benefit)........................................... -- 2,584 2,227 (22,179) 5,210 (251) 3,850
Income Tax Expense (Benefit) (4)...................... -- -- -- -- (4,692) -- 1,514
Net Income (Loss)..................................... -- 2,584 2,227 (22,179) 9,902 (251) 2,336
Earnings (Loss) per Common Share (5).................. -- -- -- -- 0.66 (0.02) 0.13
OTHER FINANCIAL DATA:
EBITDA (6)............................................ -- $ 6,245 $ 23,422 $ 35,855 $ 77,645 $31,684 $43,468
Net Cash Provided By (Used In) Operating Activities
(7)................................................. -- 38,042 103,112 (115,485) 58,880 40,642 47,260
Capital Expenditures (8).............................. -- 34,978 123,600 74,477 73,652 44,770 64,771
Ratio of Earnings to Fixed Charges (9)................ -- 11.1x 3.0x N.M. 1.3x 1.0x 1.5x
Ratio of EBITDA to Interest Expense (6)............... -- -- -- -- 4.4x 3.7x 5.3x
OPERATING DATA:
Sales Volumes:
Oil (MBbl).......................................... -- 670 2,850 4,286 6,057 2,630 3,008
Gas (MMcf).......................................... -- 1,484 3,704 7,234 12,393 5,619 7,016
MBOE................................................ -- 917 3,467 5,492 8,123 3,567 4,178
Average Prices (10):
Oil (per Bbl)....................................... -- $ 16.18 $ 13.82 $ 14.24 $ 17.39 $ 17.77 $ 19.80
Gas (per Mcf)....................................... -- 1.64 1.81 1.76 1.82 1.72 2.86
BOE (per BOE)....................................... -- 14.48 13.30 13.42 15.75 15.81 19.05
Lease Operating Expenses (per BOE).................... -- $ 5.45 $ 4.10 $ 4.29 $ 3.70 $ 3.99 $ 3.95
</TABLE>
<TABLE>
<CAPTION>
AS OF
AS OF DECEMBER 31, JUNE 30,
---------------------------------------- ----------
1992 1993 1994 1995 1996
------- -------- -------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Oil and Gas Assets, Net............................................ $31,557 $122,933 $160,950 $180,582 $216,380
Total Assets....................................................... 37,396 132,172 181,982 216,095 256,721
Long-Term Debt..................................................... -- 13,448 154,039 171,692 128,160
Deferred Revenue on Production Payments(11)........................ 32,347 108,784 -- -- --
Stockholders' Equity............................................... 349 (825) 9,703 19,976 84,452
</TABLE>
(See footnotes on following page)
21
<PAGE> 22
- ---------------
(1) Historical 1992 Company data is presented for the period from the date of
formation of the Company on April 20, 1992 through December 31, 1992.
Historical company data reflect the acquisitions of Main Pass 69 on June
11, 1992, the East Bay Complex on June 10, 1993, and a 12.5% minority
interest thereon on December 7, 1994.
(2) Represents combined revenues and direct operating expenses for (i) all of
Shell's interest in Main Pass 69 and the East Bay Complex until the
acquisition by the Company of 87.5% of such interests on June 11, 1992 and
June 10, 1993, respectively and (ii) the 12.5% ownership of Main Pass 69
and the East Bay Complex acquired by Franks Petroleum, Inc. on June 11,
1992 and June 10, 1993, respectively, until acquired by the Company on
December 7, 1994.
(3) The amount shown for the year ended December 31, 1994 represents primarily
the excess of the purchase price of the Production Payments over the book
value of the Production Payments liability as of December 7, 1994.
(4) The Company was formed as an S corporation under the Internal Revenue Code
and, as such, all income taxes were the obligation of the Company's
stockholders. Therefore, through the date of the Initial Offerings, no
historical federal or state income tax expense has been provided for in the
financial statements. In conjunction with the Initial Offerings, the
Company converted to a C corporation under the Internal Revenue Code. The
Company recorded a deferred tax asset of $6.3 million, offset by a
valuation allowance of $6.3 million at December 31, 1994 and a deferred tax
asset of $4.7 million at December 31, 1995. As a result of the reversal of
the valuation allowance, the Company recorded a net income tax benefit of
$4.7 million in the year ended December 31, 1995.
(5) If the Company had recognized a tax provision at statutory rates for the
year ended December 31, 1995, rather than an income tax benefit, earnings
per common share would have been $0.22 for such period. Earnings per share
has not been presented for periods prior to or including the date of the
Initial Offerings, as these amounts would not be meaningful or indicative
of the ongoing entity.
(6) Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDA has not been reduced for the recognition of noncash revenues
associated with the Production Payments. EBITDA is not intended to
represent cash flow in accordance with generally accepted accounting
principles and does not represent the measure of cash available for
distribution. EBITDA is not intended as an alternative to earnings from
continuing operations or net income.
(7) Cash flow from operating activities in 1992 and 1993 includes $36.8 million
and $95.7 million, respectively, from the sale of the Production Payments.
Cash flow from operating activities for the year ended December 31, 1994
was reduced by $123.6 million related to the repurchase of the Production
Payments.
(8) Includes $34.3 million in the year ended December 31, 1992 related to the
acquisition of Main Pass 69. Includes $115.5 million in the year ended
December 31, 1993 related to the acquisition of the East Bay Complex.
(9) For purposes of determining the ratio of earnings to fixed charges,
earnings are defined as earnings from continuing operations before income
taxes, plus fixed charges. Fixed charges consist of interest expense on all
indebtedness. The ratio for the year ended December 31, 1994 is not
meaningful because earnings were inadequate to cover fixed charges by $22.3
million.
(10) Excludes results of hedging activities which increased (decreased) revenue
recognized in the 1993, 1994 and 1995 periods by $1.2 million, $1.7 million
and $(0.5) million, respectively. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $14.23,
$14.56 and $17.27 in the years ended December 31, 1993, 1994 and 1995,
respectively, and the average gas price per Mcf received was $1.81 and
$1.84 in the years ended December 31, 1994 and 1995, respectively. The
Company did not enter into any hedging activities relating to oil during
1992 or relating to gas during 1992 and 1993. Hedging activities decreased
revenue recognized in the six months ended June 30, 1995 and 1996 by $1.0
million and $10.5 million, respectively. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $17.32 and
$17.92 in the six months ended June 30, 1995 and 1996, respectively, and
the average gas price per Mcf received was $1.75 and $2.17 in the six
months ended June 30, 1995 and 1996, respectively.
(11) Amounts represent deferred revenues recognized from the sale of the
Production Payments. See Note 4 to the consolidated financial statements of
the Company.
22
<PAGE> 23
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED PRO FORMA FINANCIAL INFORMATION
The following unaudited pro forma balance sheet as of June 30, 1996 gives
effect to the Notes Offering and the Central Gulf Acquisition, as if they had
occurred on June 30, 1996. The unaudited pro forma statements of operations for
the year ended December 31, 1995 and for the six months ended June 30, 1996,
give effect to the Notes Offering, the Central Gulf Acquisition and the March
1996 public offering of shares of Common Stock by the Company (the "March 1996
Offering") as if they had occurred on January 1, 1995. The Central Gulf
Acquisition has been accounted for using the purchase method of accounting. Such
unaudited pro forma financial information has been prepared based on estimates
and assumptions deemed by the Company to be appropriate and does not purport to
be indicative of the financial position or results of operations which would
actually have been obtained if the Notes Offering, the Central Gulf Acquisition
and the March 1996 Offering had occurred as presented in such statements or
which may be obtained in the future. In addition, future results may vary
significantly from the results reflected in such statements due to oil and gas
production declines, price changes, future supply and demand, financial
instrument agreements, future acquisitions and other factors. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
The pro forma financial information should be read in conjunction with the
historical financial statements of the Company and the audited financial
information on the Central Gulf Properties which are included elsewhere in this
Prospectus.
23
<PAGE> 24
FLORES & RUCKS, INC.
CONSOLIDATED PRO FORMA STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1996
<TABLE>
<CAPTION>
ADJUSTMENTS FOR
PURCHASE OF
CENTRAL GULF OTHER
HISTORICAL PROPERTIES ADJUSTMENTS PRO FORMA
---------- --------------- ----------- -----------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales................... $69,115,492 $29,466,836(a) $ 2,159,600(b) $100,741,928
Plant processing income............. (33,473) (33,473)
----------- ----------- ----------- ------------
Total revenues................... 69,082,019 29,466,836 2,159,600 100,708,455
OPERATING EXPENSES:
Lease operations.................... 16,522,030 5,300,735(a) 21,822,765
Severance taxes..................... 5,521,763 5,521,763
Depreciation, depletion and
amortization..................... 28,973,040 11,634,986(a) 40,608,026
----------- ----------- ----------- ------------
Total operating expenses......... 51,016,833 16,935,721 67,952,554
General and administrative expenses... 6,025,000 225,000(a) 6,250,000
Interest expense...................... 8,188,026 6,949,243(c) 13,083,848
(2,448,671)(d)
351,250(e)
44,000(f)
Other expense......................... 1,779 1,779
----------- ----------- ----------- ------------
Net income before taxes............... 3,850,381 12,306,115 (2,736,222) 13,420,274
Income tax expense (benefit).......... 1,514,704 4,737,854(g) (1,053,445)(g) 5,199,113
----------- ----------- ----------- ------------
Net income............................ $2,335,677 $ 7,568,261 $(1,682,777) $ 8,221,161
=========== =========== =========== ============
Weighted average common shares
outstanding......................... 17,620,538 18,046,332(h)
Earnings per common share............. $ 0.13 $ 0.46
</TABLE>
24
<PAGE> 25
FLORES & RUCKS, INC.
CONSOLIDATED PRO FORMA STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1995
<TABLE>
<CAPTION>
ADJUSTMENTS
FOR PURCHASE OF
CENTRAL GULF OTHER
HISTORICAL PROPERTIES ADJUSTMENTS PRO FORMA
----------- --------------- ----------- -----------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales................... $127,406,084 $45,883,186(a) $ 2,869,064(b) $176,158,334
Plant processing income............. 564,042 564,042
------------ ----------- ----------- ------------
Total revenues................... 127,970,126 45,883,186 2,869,064 176,722,376
OPERATING EXPENSES:
Lease operations.................... 30,023,426 12,877,310(a) 42,900,736
Severance taxes..................... 10,023,104 10,023,104
Depreciation, depletion and
amortization..................... 54,083,782 23,587,293(a) 77,671,075
------------ ----------- ----------- ------------
Total operating expenses......... 94,130,312 36,464,603 130,594,915
General and administrative expenses... 11,312,153 450,000(a) 11,762,153
Interest expense...................... 17,620,226 12,985,779(c) 26,406,082
(4,990,423)(d)
702,500(e)
88,000(f)
Other income.......................... (302,597) (302,597)
------------ ----------- ----------- ------------
Net income before taxes............... 5,210,032 8,968,583 (5,916,792) 8,261,823
Income tax expense (benefit).......... (4,692,263) 3,452,904(g) (2,277,965)(g) (3,517,324)
------------ ----------- ----------- ------------
Net income............................ $ 9,902,295 $ 5,515,679 $(3,638,827) $11,779,147
============ =========== =========== ============
Weighted average common shares
outstanding......................... 15,043,122 15,043,122
Earnings per common share............. $ 0.66 $ 0.78
</TABLE>
25
<PAGE> 26
FLORES & RUCKS, INC.
CONSOLIDATED PRO FORMA BALANCE SHEETS
AS OF JUNE 30, 1996
<TABLE>
<CAPTION>
ADJUSTMENTS
FOR PURCHASE OF
CENTRAL GULF OTHER
HISTORICAL PROPERTIES(A) ADJUSTMENTS PRO FORMA
----------- --------------- ----------- -----------
<S> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents........ $ 819,468 $33,232,500(i) $34,051,968
Joint interest receivables....... 1,229,810 1,229,810
Oil and gas sales receivables.... 16,112,617 16,112,617
Accounts receivable-other........ 3,700,000 3,700,000
Prepaid expenses................. 1,019,583 1,019,583
Other current assets............. 1,370,150 1,370,150
------------ ------------ ----------- ------------
Total current assets..... 24,251,628 -- 33,232,500 57,484,128
Oil and gas properties -- full cost
method:
Evaluated........................ 332,287,198 $71,948,800 404,235,998
Less accumulated DD&A............ (143,013,084) (143,013,084)
------------ ------------ ------------
189,274,114 71,948,800 261,222,914
Unevaluated properties excluded
from amortization............. 27,106,066 44,851,200 71,957,266
Other assets:
Furniture and equipment, less
accumulated depreciation of
$1,891,211.................... 2,793,110 2,793,110
Restricted deposits.............. 5,269,835 5,269,835
Deferred financing costs......... 4,823,582 6,087,500 (j) 10,911,082
Deferred tax asset............... 3,202,863 3,202,863
------------ ------------ ----------- ------------
Total assets............. $256,721,198 $116,800,000 $39,320,000 $412,841,198
============ ============ =========== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued
liabilities................... $ 37,240,733 $37,240,733
Oil and gas sales payable........ 4,548,963 4,548,963
Accrued interest................. 1,447,287 1,447,287
------------ ------------
Total current
liabilities............ 43,236,983 43,236,983
Long-term debt..................... 128,160,111 $116,800,000 $40,200,000 (i) 284,280,111
(880,000)(k)
Other noncurrent liabilities....... 638,609 638,609
Deferred hedge revenue............. 233,167 233,167
Stockholders' equity:
Preferred stock.................. -- --
Common stock, $.01 par value;
authorized 100,000,000 shares;
issued and outstanding
19,555,223 shares at June 30,
1996.......................... 195,552 195,552
Paid-in capital.................. 89,734,455 89,734,455
Retained earnings (deficit)...... (5,477,679) (5,477,679)
------------ ------------
Total stockholders'
equity................. 84,452,328 84,452,328
------------ ------------ ----------- ------------
Total liabilities and
stockholders' equity... $256,721,198 $116,800,000 $39,320,000 $412,841,198
============ ============ =========== ============
</TABLE>
26
<PAGE> 27
FLORES & RUCKS, INC.
NOTES TO PRO FORMA FINANCIAL STATEMENTS
1. BASIS FOR PRESENTATION OF PRO FORMA FINANCIAL STATEMENTS
The unaudited pro forma balance sheet as of June 30, 1996 gives effect to
the Notes Offering and the Central Gulf Acquisition, as if they had occurred on
June 30, 1996. The unaudited pro forma statements of operations for the year
ended December 31, 1995 and for the six months ended June 30, 1996, give effect
to the Notes Offering, the Central Gulf Acquisition and the March 1996 Offering
as if they had occurred on January 1, 1995. The Central Gulf Acquisition has
been accounted for using the purchase method of accounting. Such unaudited pro
forma financial information has been prepared based on estimates and assumptions
deemed by the Company to be appropriate and does not purport to be indicative of
the financial position or results of operations which would actually have been
obtained if the Notes Offering, Central Gulf Acquisition, and the March 1996
Offering had occurred as presented in such statements, or which may be obtained
in the future. In addition, future results may vary significantly from the
results reflected in such statements due to oil and gas production declines,
price changes, future supply and demand, financial instrument agreements, future
acquisitions and other factors. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
The pro forma financial information should be read in conjunction with the
historical financial statements of the Company, and the audited financial
information on the Central Gulf Properties which are included elsewhere in this
Prospectus.
2. ADJUSTMENTS
The pro forma adjustments included in the pro forma financial statements
are described as follows by the alphabetical notation:
(a) Reflects increases relating to the purchase of the Central Gulf
Properties, including the proceeds from the Notes used for the acquisition of
the Central Gulf Properties.
(b) Reflects an increase in pricing from historical pricing to that which
the Company would have realized under its contracts.
(c) Reflects an increase in interest expense of $15.6 million and $7.8
million for the twelve months ended December 31, 1995 and the six months ended
June 30, 1996 respectively, relating to the issuance of the Notes (at a coupon
of 9.75%) partially offset by a reduction of $2.6 million and $.9 million for
the twelve months ended December 31, 1995 and the six months ended June 30, 1996
respectively, relating to the repayment of debt which is assumed repaid with
proceeds of the Notes Offering and the March 1996 Offering.
(d) Reflects a reduction to interest expense associated with the
capitalization of interest on unevaluated property costs incurred in conjunction
with the acquisition of the Central Gulf Properties. This reduction is partially
offset by a reduction in the average interest rate used in the calculation of
capitalized interest on other unevaluated properties resulting from the issuance
of the Notes at a lower interest rate than the Company's existing average
interest rate.
(e) Reflects an increase in interest expense related to additional
amortization of deferred financing costs resulting from underwriting discounts,
fees and other expenses associated with the issuance of the Notes.
(f) Reflects an increase in interest expense relating to the amortization
of $.9 million of original issue discount.
(g) Reflects an adjustment in income tax expense relating to the change in
pre-tax income resulting from the above adjustments. The adjustment is based
upon a blended Federal and Louisiana state income tax rate of 38.5%.
(h) Reflects the increase in common shares from the March 1996 Offering,
the proceeds of which were assumed to have been utilized to repay debt.
27
<PAGE> 28
(i) Reflects a $160.0 million increase in long-term debt associated with
the issuance of the Notes partially offset by a $3.0 million reduction relating
to a payment on the June 30, 1996 Revolving Credit Facility balance and the
$116.8 million purchase price of the Central Gulf Acquisition reflected in note
(a).
(j) Reflects an increase in deferred financing costs relating to
underwriting discounts, fees and other expenses associated with the Notes.
(k) Reflects a reduction to long-term debt relating to $.9 million of
original issue discount.
3. PREFERENTIAL PURCHASE RIGHTS
Certain properties included in the Central Gulf Acquisition are subject to
preferential purchase rights. If such preferential purchase rights are exercised
in full, pro forma revenues for the six months ended June 30, 1996, would
decrease by $2.2 million, lease operating expenses and depreciation, depletion
and amortization expense would decrease by $.2 million and $.9 million,
respectively, and interest expense would increase by $.1 million, resulting in a
$.7 million decrease in pro forma net income after taxes. For the twelve months
ended December 31, 1995, pro forma revenues would decrease by $.8 million, lease
operating expenses and depreciation, depletion and amortization expense would
decrease by $.3 million and $.5 million, respectively, and interest expense
would increase by $.2 million, resulting in a $.1 million decrease in pro forma
net income after taxes.
28
<PAGE> 29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion and analysis of the Company's financial
condition and results of operations and should be read in conjunction with the
Company's consolidated financial statements and the notes thereto included
elsewhere in or incorporated by reference into this Prospectus.
GENERAL
The Company is a Delaware corporation formed in September 1994 to acquire
and own 100% of the outstanding Common Stock of FRI Louisiana. FRI Louisiana was
formed in April 1992 to take advantage of opportunities to acquire and develop
certain offshore properties in the Louisiana Gulf. FRI Louisiana acquired from
Shell Main Pass 69 in June 1992 and the East Bay Complex in June 1993. In
connection with the acquisition and development of its properties prior to the
Company's initial public offerings (the "Initial Offerings"), FRI Louisiana
entered into several transactions including, but not limited to (i) the sale of
volumetric production payments (the "Production Payments"), (ii) obtaining
secured loans (the "JEDI Loans") from the Joint Energy Development Investments
Limited Partnership ("JEDI"), a venture between the California Public Employees
Retirement System and Enron Capital Corp. and (iii) the assignment of a 12.5%
interest in Main Pass 69 and the East Bay Complex to Franks Petroleum, Inc.
("Franks").
On December 28, 1993, in order to reduce state franchise tax liabilities,
FRI Louisiana transferred its 87.5% interest in Main Pass 69 and the East Bay
Complex to a Louisiana limited liability company (the "LLC") in return for an
87.5% ownership interest in the LLC. Franks also contributed its interest in
such properties to the LLC in return for a 12.5% ownership interest in the LLC
(the "Minority Interest").
In conjunction with the Initial Offerings of 5,790,000 shares of Common
Stock at $10 per share, the sale of the $125,000,000 Senior Notes and entering
into the $50 million Revolving Credit Facility, the Company (i) acquired 100% of
the outstanding common stock of FRI Louisiana from James C. Flores, trusts for
the benefit of his children and William W. Rucks, IV in exchange for a total of
8,248,000 shares of Common Stock, (ii) repurchased the Production Payments,
(iii) purchased the Minority Interest, and (iv) repaid other debt owed by the
Company, including the JEDI Loans.
On March 19, 1996, the Company completed a public offering of 4,500,000
shares of Common Stock at a price of $14.75 per share. Net proceeds from this
offering were approximately $62.2 million, of which $15.4 million was used to
repay a note payable to Shell Offshore, Inc. and approximately $33.0 million was
used to repay indebtedness under the Revolving Credit Facility.
Since acquiring the East Bay Complex and Main Pass 69, the Company has
reduced field costs at both operations primarily by combining administrative
functions relating to both properties, reducing the number of operating
personnel and providing incentive compensation. For example, the two properties,
which were formerly operated as separate cost centers, are now integrated with
respect to logistics, administration and other support functions. In addition,
the Company was able to reduce the number of field personnel by approximately
37% at the East Bay Complex and 44% at Main Pass 69. The former cost centers
were also converted to profit centers with compensation levels tied to operating
and financial targets. Primarily as a result of the aforementioned actions and
increased production, lease operating expenses decreased by 28% from $5.45 per
BOE for the period from inception (April 20, 1992) through December 31, 1992 to
$3.95 per BOE for the six months ended June 30, 1996.
On July 10, 1996, the Company entered into a Purchase and Sale Agreement to
acquire the Central Gulf Properties, consisting of interests in oil and gas
producing fields situated in the Gulf of Mexico, offshore Louisiana, for an
anticipated purchase price of approximately $117 million. The closing of the
Central Gulf Acquisition will occur concurrently with the consummation of the
Notes Offering, subject to approvals by the management and Board of Directors of
the Company and Mobil, and subject to preferential purchase rights of third
parties on some of the Central Gulf Properties.
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<PAGE> 30
Management believes the acquisition of the Central Gulf Properties, along
with the Company's recent exploration efforts in the onshore coastal regions of
Louisiana, substantially increase the Company's future exploration, exploitation
and development opportunities while diversifying the risks associated with these
activities. The proximity of these new areas to the Company's existing
properties allows for economies of scale associated with leveraging the
Company's current corporate infrastructure. Additionally, management believes it
will be able to take advantage of its unique operating strengths in pursuing
each of these areas. In particular, application of the geological, geophysical
and operational experience derived from its existing properties may enhance the
likelihood of success in these new areas, due in part to the geological
similarities shared by the entire Louisiana Gulf region.
The following table reflects certain information with respect to the
Company's oil and gas properties. Sales volumes, revenues and average sales
prices presented below have been segregated into those subject to Production
Payments and amounts in excess of Production Payments in the applicable periods.
The amounts for the year ended December 31, 1993 and for the year ended December
31, 1994 do not reflect the 12.5% Minority Interest prior to its acquisition on
December 7, 1994.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------- -----------------
1993 1994 1995 1995 1996
------- ------- -------- ------- -------
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
SALES VOLUMES
Oil (MBbls)
Excess over Production Payments........ 1,537 2,771 6,057 2,630 3,008
Production Payments.................... 1,313 1,515 -- -- --
------- ------- -------- ------- -------
Total Oil Volumes...................... 2,850 4,286 6,057 2,630 3,008
======= ======= ======== ======= =======
Gas (MMcf)
Excess over Production Payments........ 1,542 3,456 12,393 5,619 7,016
Production Payments.................... 2,162 3,778 -- -- --
------- ------- -------- ------- -------
Total Gas Volumes...................... 3,704 7,234 12,393 5,619 7,016
======= ======= ======== ======= =======
REVENUES (1)
Oil
Excess over Production Payments........ $24,477(2) $43,106(2) $105,360 $46,728 $59,561
Production Payments.................... 14,918 17,906 -- -- --
------- ------- -------- ------- -------
Total Oil Revenues..................... $39,395 $61,012 $105,360 $46,728 $59,561
======= ======= ======== ======= =======
Gas
Excess over Production Payments........ $ 3,340 $ 6,757 $ 22,581 $ 9,650 $20,032
Production Payments.................... 3,376 5,951 -- -- --
------- ------- -------- ------- -------
Total Gas Revenues..................... $ 6,716 $12,708 $ 22,581 $ 9,650 $20,032
======= ======= ======== ======= =======
AVERAGE SALES PRICES (1)
Oil (per Bbl)
Excess over Production Payments........ $ 15.93(2) $ 15.56(2) $ 17.39 $ 17.77 $ 19.80
Production Payments.................... 11.36 11.82 -- -- --
Net average oil price.................. 13.82 14.24 17.39 17.77 19.80
Gas (per Mcf)
Excess over Production Payments........ $ 2.17 $ 1.96 $ 1.82 $ 1.72 $ 2.86
Production Payments.................... 1.56 1.58 -- -- --
Net average gas price.................. 1.81 1.76 1.82 1.72 2.86
BOE (per BOE)
Excess over Production Payments........ $ 15.51 $ 14.90 $ 15.75 $ 15.81 $ 19.05
Production Payments.................... 10.93 11.12 -- -- --
Net average price...................... 13.30 13.42 15.75 15.81 19.05
Severance Taxes (3)......................... $ 4,998 $ 6,747 $ 10,023 $ 4,745 $ 5,522
Lease Operating Expenses (3)................ $14,204 $23,577 $ 30,023 $14,225 $16,522
Lease Operating Expenses (per BOE).......... $ 4.10 $ 4.29 $ 3.70 $ 3.99 $ 3.95
</TABLE>
(See footnotes on following page)
30
<PAGE> 31
- ---------------
(1) Excludes results of hedging activities which increased (decreased) revenue
recognized in the years ended December 31, 1993, 1994 and 1995 by $1.2
million, $1.7 million and $(0.5) million, respectively. Including the
effect of hedging activities, the Company's average oil price per Bbl
received was $14.23, $14.56 and $17.27 in the years ended December 31,
1993, 1994 and 1995, respectively, and the average gas price per Mcf
received was $1.81 and $1.84 in the years ended December 31, 1994 and 1995,
respectively. The Company did not enter into any hedging activities
relating to gas during 1993. Hedging activities decreased revenue
recognized in the six months ended June 30, 1995 and 1996 by $1.0 million
and $10.5 million, respectively. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $17.32 and
$17.92 and the average gas price per Mcf received was $1.75 and $2.17 in
the six months ended June 30, 1995 and 1996, respectively.
(2) Includes Main Pass 69 sales of 629 MBbls and 800 MBbls for the years ended
December 31, 1993 and 1994, respectively, subject to a long-term contract
at prices averaging $1.23 per Bbl below prevailing market prices for the
year ended December 31, 1993 and $1.29 per Bbl for the eleven months ended
November 30, 1994. The long-term contract was terminated in connection with
the Initial Offerings. See "Business -- Oil and Gas Marketing and Major
Customers."
(3) Volumes delivered under production payments were received by Enron Reserve
Acquisition Corp. ("ERAC") free and clear of severance taxes and lease
operating expenses. These costs were borne in full by the Company under the
terms of the Production Payments.
RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996
Revenues. The following table reflects an analysis of differences in the
Company's oil and gas revenues (expressed in thousands of dollars) between the
six months ending June 30, 1996 and the comparable period in 1995:
<TABLE>
<CAPTION>
SIX MONTHS 1996
COMPARED TO
SIX MONTHS 1995
---------------
<S> <C>
Increase (decrease) in oil and gas revenues
resulting from differences in:
Crude oil and condensate --
Price................................................... $ 6,116
Production.............................................. 6,717
--------
12,833
Natural gas --
Price................................................... 7,982
Production.............................................. 2,399
--------
10,381
Plant processing and hedging, net.......................... (10,004)
--------
Increase in oil and gas revenues............................. $ 13,210
========
</TABLE>
The Company's total revenues increased approximately $13.2 million, or 24%,
to $69.1 million for the six months ended June 30, 1996, from $55.9 million for
the comparable period in 1995. Production levels for the six months ended June
30, 1996, increased 17% to 4,178 MBOE from 3,567 MBOE for the comparable period
in 1995. The Company's average sales prices (excluding hedging activities) for
oil and natural gas for the six months ended June 30, 1996 were $19.80 per Bbl
and $2.86 per Mcf versus $17.77 per Bbl and $1.72 per Mcf in the prior period.
Revenues increased by $9.1 million due to the aforementioned production
increases and by $14.1 million as a result of increased oil and gas prices.
For the six months ended June 30, 1996, the increase in the Company's total
revenues was partially offset by a $9.5 million decrease in hedging revenues and
a $.5 million decrease in plant processing income. In order to manage its
exposure to price risks in the sale of its crude oil and natural gas, the
Company from time to
31
<PAGE> 32
time enters into price hedging arrangements. See "-- Other Matters -- Energy
swap agreements." The Company's average sales prices (including hedging
activities) for oil and natural gas for the six months ended June 30, 1996, were
$17.92 per Bbl and $2.17 per Mcf versus $17.32 per Bbl and $1.75 per Mcf in the
prior period. The Company is also contractually committed to process its gas
production from Main Pass 69 and the East Bay fields under certain processing
agreements. Plant processing income (loss) represents revenues from the sale of
natural gas liquids less the costs of extracting such liquids, which costs
include natural gas shrinkage. Income from plant processing fluctuates primarily
as a result of changes in volumes processed, and changes in prices for natural
gas in comparison to changes in prices for natural gas liquids. Such price
changes are usually not proportionate due to the generally higher price
volatility of natural gas. For the six months ended June 30, 1996, plant
processing income decreased due to natural gas liquid prices remaining
relatively stable, while natural gas prices generally increased.
Lease operating expenses. Lease operating expenses decreased to $3.95 per
BOE for the six months ended June 30, 1996, from $3.99 per BOE in the comparable
1995 period. This decrease is primarily the result of increased production at
the Company's East Bay field, which has substantial fixed operating costs due to
the capital intensive nature of the facilities and the underutilization of
capacity. For the six months ended June 30, 1996, lease operating expenses were
$16.5 million, as compared to $14.2 million in the 1995 period. This increase
partially results from fluctuations in normal operating expenses, including
operating expenses associated with increased production, as well as an increase
of $.7 million in workover expenses. For the six months ended June 30, 1996,
workover expenses were $1.3 million, as compared to $.6 million in the
comparable 1995 period.
Severance taxes. The effective severance tax rate as a percentage of oil
and gas revenues (excluding the effect of hedging activities) decreased to 6.9%
in the six months ended June 30, 1996, from 8.4% in the comparable 1995 period.
The decrease was primarily due to increased production from new wells on federal
leases and from state leases which were exempt from state severance tax under
Louisiana's severance tax abatement program.
General and administrative expenses. General and administrative expenses
per BOE decreased to $1.44 per BOE in the six months ended June 30, 1996, from
$1.57 per BOE in the comparable 1995 period. This decrease is primarily a result
of increased production in the 1996 period. For the six months ended June 30,
1996, general and administrative expenses were $6.0 million as compared to $5.6
million in the comparable 1995 period. This increase is primarily due to costs
associated with increased corporate staffing, partially offset in the 1996
period by an increase in the capitalization of a portion of the salaries paid to
employees directly engaged in the acquisition, exploration and development of
oil and gas properties.
Depreciation, depletion, and amortization expense. For the six months
ended June 30, 1996, depreciation, depletion and amortization ("DD&A") expense
was $29.0 million as compared to $23.2 million in the comparable 1995 period. On
a BOE basis, DD&A for the six months ended June 30, 1996, $6.94 per BOE as
compared to $6.50 per BOE for the six months ended June 30, 1995. This variance
can primarily be attributed to the Company's increased production and related
capital cost additions from the 1995 and 1996 drilling programs, partially
offset by the increase to proved reserves resulting from the programs.
Interest expense. For the six months ended June 30, 1996, interest expense
decreased approximately $.3 million to $8.2 million from $8.5 million in the
comparable 1995 period. This decrease in interest expense can primarily be
attributed to the repayment of a portion of the Company's debt with proceeds
from the issuance of 4,500,000 shares of Common Stock at $14.75 per share on
March 19, 1996.
Other (income) expense. Other (income) expense decreased by $.1 million in
the six months ended June 30, 1996 from the comparable 1995 period. This
decrease primarily relates to the Company recording a $.4 million loss in the
first quarter of 1996 associated with the classification of a portion of its
future swap arrangements as speculative, partially offset by the aforementioned
increase in interest income in the 1996 period.
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<PAGE> 33
Income tax expense (benefit). For the six months ended June 30, 1996, the
Company recorded income tax expense of $1.5 million. During the comparable 1995
period, no income tax benefit was recorded due to a valuation allowance which
existed at June 30, 1995.
Net income. Due to the factors described above, net income for the six
months ended June 30, 1996, increased to $2.3 million, an increase of $2.6
million from a net loss of $.3 million for the comparable 1995 period.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1995
Revenues. The following table reflects an analysis of differences in the
Company's oil and gas revenues (expressed in thousands of dollars) between the
year ended December 31, 1995, and the comparable 1994 period:
<TABLE>
<CAPTION>
YEAR ENDED 1995
COMPARED TO
YEAR ENDED 1994
---------------
<S> <C>
Increase (decrease) in oil and gas revenues resulting from differences in:
Crude oil and condensate --
Price.................................................................. $19,143
Production............................................................. 25,205
-------
44,348
Natural Gas --
Price.................................................................. 811
Production............................................................. 9,062
-------
9,873
-------
Plant processing and Hedging, net...................................... (1,646)
-------
Increase in oil and gas revenues............................................ $52,575
=======
</TABLE>
For the year ended December 31, 1995, the Company's total revenues
increased approximately $52.6 million, or 70%, to $128.0 million from $75.4
million for the comparable period in 1994. Production levels for the year ended
December 31, 1995, increased 48% to 8,123 MBOE from 5,492 MBOE for the
comparable period in 1994. The Company's average sales prices (including hedging
activities) for oil and natural gas for the year ended December 31, 1995 were
$17.27 per Bbl and $1.84 per Mcf, respectively, versus $14.56 per Bbl and $1.81
per Mcf, respectively, in the comparable 1994 period. Oil and natural gas
volumes sold pursuant to Production Payment obligations represented
approximately 35% and 52% of total sales volumes, respectively, for the year
ended December 31, 1994. As a result of the repurchase of the Production
Payments on December 7, 1994, the Company was able to sell all of its production
at market prices in 1995 as compared to previously selling a portion of its
production subject to the Production Payments at implicit contractual prices per
BOE substantially below then current market prices.
For the year ended December 31, 1995, the Company recognized additional
production of 950 MBOE and related revenues of $15.0 million associated with the
Minority Interest purchased December 7, 1994. Of the $15.0 million, $12.4
million was primarily related to production associated with the purchased
Minority Interest with the remaining $2.6 million primarily related to increased
oil prices for the 1995 period.
For the year ended December 31, 1995, the Company's total revenues were
further affected by a $2.2 million decrease in hedging revenues partially offset
by a $0.6 million increase in plant processing income. In order to manage its
exposure to price risks in the sale of its crude oil and natural gas, the
Company from time to time enters into price hedging arrangements. See "-- Other
Matters -- Energy Swap Agreements." The Company is also contractually committed
to process its gas production from Main Pass 69 and the East Bay fields under
certain processing agreements. Plant processing income (loss) represents
revenues from the sale of natural gas liquids less the costs of extracting such
liquids, which costs include natural gas shrinkage. Income from plant processing
fluctuates primarily as a result of changes in volumes processed, and changes in
33
<PAGE> 34
prices for natural gas in comparison to changes in prices for natural gas
liquids. Such price changes are usually not proportionate due to the generally
higher price volatility of natural gas. For the year ended December 31, 1995,
plant processing income increased due to higher volumes of natural gas processed
and because natural gas liquid prices remained relatively stable, while natural
gas prices generally decreased.
Lease operating expenses. On a BOE basis, lease operating expenses
decreased 14% in the year ended December 31, 1995, to $3.70 per BOE from $4.29
per BOE in the comparable period of 1994. This decrease is primarily the result
of increased production in both fields, which have substantial fixed operating
costs due to the capital intensive nature of the facilities and the
underutilization of capacity. Lease operating expenses for the year ended
December 31, 1995 were $30.0 million, as compared to $23.6 million for the
comparable 1994 period. The increase in lease operating expenses for the year
ended December 31, 1995, from the comparable 1994 period was primarily related
to the Company's operating expenses associated with increased production, the
purchase of the Minority Interest in December 1994, an increase in painting and
other preventive maintenance type programs which the Company believes are cost
effective, and increased workover costs in the 1995 period. Workover expenses
increased to $1.4 million for the year ended December 31, 1995, as compared to
$0.9 million for the comparable 1994 period.
Severance taxes. The effective severance tax rate as a percentage of
revenues decreased to 7.8% in the year ended December 31, 1995, from 8.9% in the
comparable period of 1994. This decrease was primarily due to increased
production from new wells on federal leases and from state leases which were
exempt from state severance tax under Louisiana's severance tax abatement
program.
General and administrative expenses. General and administrative expenses
per BOE decreased 26% to $1.39 per BOE in the year ended December 31, 1995 from
$1.88 per BOE in the comparable period of 1994. In the year ended December 31,
1995, general and administrative expenses were $11.3 million, as compared to
$10.4 million in the comparable 1994 period. The increase in general and
administrative expenses for the year ended December 31, 1995, from the
comparable 1994 period is primarily due to increased corporate staffing, an
increase in director and officer insurance premiums, an increase in franchise
taxes and in incentive compensation. These increases were partially offset by
the nonrecurring $0.9 million release and indemnity expenses incurred by the
Company in the year ended December 31, 1994, a decrease in legal and other
professional fees during 1995 and by an increase in the capitalization of the
salaries paid to employees directly engaged in the acquisition, exploration and
development of oil and gas properties during 1995.
Depreciation, depletion, and amortization expense. For the year ended
December 31, 1995, DD&A per BOE remained relatively unchanged at $6.66 as
compared to $6.64 in the 1994 period. Total DD&A expense for the 1995 period was
$54.1 million, as compared to $36.5 million for the comparable 1994 period. This
variance was primarily related to the Company's increased production and related
capital costs from the 1994 and 1995 drilling programs, as well as the increase
in proved reserves. Also contributing to increased DD&A expense was the December
1994 acquisition of the Minority Interest.
Interest expense. Interest expense for the year ended December 31, 1995
was $17.6 million, an increase of approximately $13.1 million from $4.5 million
for the comparable 1994 period. This increase was due primarily to interest
expense relating to the Senior Notes and the Revolving Credit Facility. This
increase was partially offset by interest which was capitalized during the year
ended December 31, 1995, of $2.8 million, as compared to $.1 million in the 1994
period.
Income tax expense (benefit). The Company was originally formed as an S
corporation under the Internal Revenue Code and, as such, all income taxes were
the obligation of the Company's stockholders. In conjunction with the Initial
Offerings, the Company converted to a C corporation under the Internal Revenue
Code. Due to a valuation allowance, the Company did not record a tax benefit for
the year ended December 31, 1994. During 1995, due to drilling successes and
increases in realized prices, the Company generated income from operations.
Based upon current estimates, management believes it is more likely than not
that the deferred tax asset will be realized. As a result, in 1995 the Company
reversed the valuation allowance and recognized a tax benefit of $4.7 million.
34
<PAGE> 35
Net income. Due to the factors described above, net income increased
approximately $32.1 million from a net loss of $22.2 million for the year ended
December 31, 1994 to net income of $9.9 million for the year ended December 31,
1995. For the year ended December 31, 1995, net income before the income tax
benefit was $5.2 million.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1993 AND 1994
On June 11, 1992, the Company acquired Main Pass 69, and on June 10, 1993,
the Company acquired the East Bay Complex, each from Shell. Due to the
significance of the East Bay Complex to the Company's operations, most of the
variances in the statements of operations between the twelve-month periods ended
December 31, 1993 and 1994 are attributable to the inclusion of the East Bay
Complex for the full twelve-month period ended December 31, 1994 versus
approximately six months of post-acquisition activity for the twelve-month
period ended December 31, 1993. In addition, in conjunction with the Initial
Offerings and entering into the Revolving Credit Facility, the Company
repurchased the Production Payments, purchased the Minority Interest in the LLC,
and repaid other debt owed by the Company.
Revenues. The Company's total revenues increased approximately $27.9
million, or 59%, to $75.4 million for the year ended December 31, 1994, from
$47.5 million for the comparable period in 1993. Production levels for the year
ended December 31, 1994 increased 59% to 5,492 MBOE from 3,462 MBOE for the
comparable period in 1993. The Company's average sales prices (including hedging
activities) for oil and natural gas for the year ended December 31, 1994 were
$14.56 per Bbl and $1.81 per Mcf respectively, versus $14.23 per Bbl and $1.81
per Mcf, respectively, in the prior year. Oil and natural gas volumes sold
pursuant to volumetric production payment obligations represented approximately
35% and 52%, respectively, of the Company's production for the year ended
December 31, 1994. Subsequent to the Initial Offerings, none of the Company's
production was subject to such obligations.
The aforementioned increase in the Company's total revenues was impacted
primarily by the increase of $28 million in oil and gas sales associated with
the East Bay Complex, which the Company acquired in June 1993. This increase in
production was a result of a full period of reporting for the East Bay Complex
in 1994 as well as from the completion of several exploitation and development
projects. In addition, the Company recognized approximately an additional 1/8
production and related revenues of $1 million subsequent to the purchase of the
Minority Interest in the LLC. Finally, revenues were higher as a result of the
repurchase of the Production Payments due to the Company being able to sell all
of its production at market prices as compared to previously selling a portion
of its production subject to the Production Payments at implicit contractual
prices per BOE substantially below current market prices. Revenues increased by
approximately $780,000 relating to these increased prices.
The increase in the Company's total revenues was further affected by a $0.6
million increase in hedging revenues partially offset by a $0.2 million decrease
in plant processing income. In order to manage its exposure to price risks in
the sale of its crude oil and natural gas, the Company from time to time enters
into price hedging arrangements. See "-- Other Matters -- Energy Swap
Agreement." The Company is also contractually committed to process its gas
production from Main Pass 69 and the East Bay Complex under certain processing
agreements. Plant processing income (loss) represents the net of revenues from
the sale of natural gas liquids less the costs of extracting such liquids, which
costs include natural gas shrinkage. Income from plant processing fluctuates
primarily as a result of changes in volumes processed, and changes in prices for
natural gas in comparison to changes in prices for natural gas liquids. Such
price changes are usually not proportionate due to the generally higher price
volatility of natural gas. For the year ended December 31, 1994, plant
processing income decreased due to a downward trend of natural gas liquid prices
during the first three quarters of the year, a period during which natural gas
prices remained relatively high. During the latter part of the year, natural gas
liquids prices increased while natural gas prices were lower, which reduced the
loss incurred earlier during the year.
Direct operating expenses. The majority of the Company's production is
from oil wells, which are typically more expensive to operate than gas wells. As
such, the Company's operating expenses per BOE may be higher than those incurred
by other independents whose production is primarily from gas wells. Lease
35
<PAGE> 36
operating expenses increased 66% to $23.6 million for the year ended December
31, 1994, from $14.2 million in the comparable period of 1993. The increase
corresponds with the increase in production levels of oil and natural gas
relating to the acquisition of the East Bay Complex. On a BOE basis, lease
operating expenses increased 4% in the year ended December 31, 1994, to $4.29
per BOE from $4.11 per BOE in the comparable period of 1993. The increased rate
results from increased production at the East Bay Complex, where lease operating
expenses per BOE are higher than at Main Pass 69. The East Bay Complex
experiences higher lease operating expenses per BOE as a result of a number of
factors, including: (i) the capital intensive nature of its facilities and the
underutilization of capacity at these facilities (which were originally
constructed to handle significantly higher production) (ii) differing weather,
water depth, and geographic concentration of wells (resulting in greater field
personnel transportation costs and dredging costs) and (iii) approximately 2.3
times the number of wells per BOE produced. In addition, lease operating
expenses increased by approximately $300,000 relating to the purchase of the
Minority Interest in December 1994.
The effective severance tax rate as a percentage of revenues decreased from
10.6% in the year ended 1993 to 8.9% in the comparable period in 1994. This
decline was due to the additional production from the East Bay Complex, which
had a lower severance tax rate than production from Main Pass 69. The severance
tax rate for the East Bay Complex is lower than that for Main Pass 69 as a
result of federal leases within the East Bay Complex, which are exempt from
severance taxes.
General and administrative expenses. General and administrative expenses
increased 108% to $10.4 million for the year ended December 31, 1994, from $5.0
million in the comparable period of 1993 due primarily to increased staffing as
a result of the acquisition of the East Bay Complex, the payment of directors'
fees, and legal matters, all of which were resolved in 1994, including a one
time charge to earnings in the 1994 period of $0.9 million related to release
and indemnity expenses.
Depreciation, depletion, and amortization expense. Depreciation, depletion
and amortization expense increased by approximately 82% to $36.5 million for the
year ended December 31, 1994, from $20.1 million in the comparable period of
1993. The depreciation, depletion and amortization expense rate increased to
$6.64 per BOE for the year ended December 31, 1994 from $5.80 per BOE for the
year ended December 31, 1993. This increase primarily results from the
acquisition of the East Bay Complex which has a higher depreciation, depletion
and amortization rate per BOE, primarily due to a higher acquisition cost per
BOE and to significant future capital and abandonment costs. In addition,
depreciation, depletion and amortization expense increased in 1994 relating to
the December 7, 1994 acquisition of the Minority Interest in the LLC and the
purchase of the net profits interest.
Interest expense. Interest expense increased approximately 309% to $4.5
million for the year ended December 31, 1994, from $1.1 million in the
corresponding period of 1993 due primarily to additional indebtedness of the
Company. The Company recorded interest expense of $1.1 million for the month of
December 1994 relating to the Senior Notes.
Income tax expense (benefit). The Company was formed as an S corporation
under the Internal Revenue Code and, as such, all income taxes were the
obligation of the Company's stockholders. Therefore, through December 7, 1994,
no historical federal or state income tax expense has been provided for in the
financial statements. In conjunction with the Initial Offerings, the Company
converted to a C corporation under the Internal Revenue Code. Due to a valuation
allowance, the Company has not recorded a tax benefit as of December 31, 1994.
See Note 6 to the Consolidated Financial Statements.
Interest income and other revenue. Interest income and other revenue
increased from $172,695 for the year ended December 31, 1993, to $748,479 in the
comparable 1994 period. Included in the 1994 total was $460,850 relating to the
Company's consolidated share of a management fee which the Company charged the
LLC. No management fee was recorded in 1993 as the LLC was not formed until
December 28, 1993. In addition, in 1994 the Company had additional interest
income relating to notes from current and former stockholders.
One time charges in 1994. On December 7, 1994 in connection with the
Initial Offerings and related transactions, the Company recorded a loss on the
repurchase of the production payments of $15.7 million
36
<PAGE> 37
which represented the amount paid to repurchase the Production Payments in
excess of the book value. In addition, the Company recorded as an expense in the
fourth quarter of 1994, the balance in deferred financing associated with the
JEDI Loans on December 7, 1994 when the loans were paid in full.
Net income. Due to the factors described above, net income decreased from
$2.2 million for the year ended December 31, 1993 to a loss of $22.2 million for
the comparable period in 1994. Excluding the one-time charges discussed above,
the 1994 loss would have been $5.5 million.
LIQUIDITY AND CAPITAL RESOURCES
The following summary table reflects comparative cash flows for the Company
for the years ended December 31, 1993, 1994 and 1995 and the six months ended
June 30, 1995 and 1996:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------- -------------------
1993 1994 1995 1995 1996
-------- --------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Net cash provided by (used in) operating
activities(1)............................ $103,112 $(115,485) $ 58,880 $ 40,642 $ 47,260
Net cash used in investing activities...... (100,741) (46,607) (77,699) (46,566) (66,867)
Net cash provided by (used in) financing
activities............................... (2,400) 162,462 18,463 5,463 20,214
</TABLE>
- ---------------
(1) Cash flow from operating activities for the year ended December 31, 1994
was reduced by $123.6 million related to the repurchase of the Production
Payments. Cash flow from operating activities in 1993 includes $95.7
million from the sale of a Production Payment.
For the six months ended June 30, 1996, net cash provided by operating
activities increased by $6.6 million. This increase relates primarily to
increased revenues, partially offset by increases in lease operating expenses,
severance taxes and general and administrative expenses. Accounts receivable
increased by $3.0 million for the six months ended June 30, 1996. The increase
was primarily related to a $3.7 million receivable for monies deposited in
association with the potential acquisition of certain oil and gas properties.
Subsequent to June 30, 1996, a third party exercised preferential purchase
rights to acquire the properties. This increase was partially offset by a
decrease in oil and gas sales receivables. During the six months ended June 30,
1995, accounts receivable increased by $2.3 million primarily relating to an
increase in oil and gas sales receivables. Accounts payable increased by $22.1
million during the 1996 period as compared to an increase of $18.7 million in
the comparable 1995 period. The increase in accounts payable is primarily a
result of variances in vendors payable resulting from a more aggressive drilling
program in the 1996 period.
Cash used in investing activities during the six months ended June 30,
1996, increased to $66.9 million as compared to $46.6 million in the comparable
1995 period, reflecting the more aggressive 1996 drilling program.
Financing activities during the six months ended June 30, 1996, generated
cash of $20.2 million, as compared to $5.5 million in the comparable 1995
period. The increase in cash during the 1996 period was primarily a result of
the issuance of 4,500,000 shares of common stock at $14.75 per share on March
19, 1996, of which the Company's net proceeds totaled approximately $62.2
million. This increase in cash was offset by the payment of a $13 million note
to Shell Offshore, Inc. and a $29.2 million reduction in net borrowings on the
Company's Revolving Credit Facility. During the 1995 period, the Company
increased its borrowings on the Revolving Credit Facility by $15 million. In
addition, the Company received cash from the sale of stock in the 1995 period of
$.4 million.
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<PAGE> 38
Capital requirements. The Company's capital investments to date have
focused primarily on exploration, acquisitions and development of proved
properties. The Company's expenditures for property acquisition, exploration and
development for the years ended December 31, 1993, 1994 and 1995 and the six
months ended June 30, 1995 and 1996 are as follows:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
---------------------------- -----------------
1993 1994 1995 1995 1996
-------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
(IN THOUSANDS)
Property acquisition costs of evaluated
properties.................................... $115,490 $25,442 $ 624 $ 30 $ 39
Property acquisition costs of unevaluated
properties.................................... -- 14,736 2,381 1 3,069
Exploration costs (drilling and completion)..... 422 8,467 12,153 7,339 16,029
Development costs (drilling and completion)..... 6,631 21,634 42,443 29,642 31,113
Abandonment costs............................... 1,057 727 236 33 154
Geological and geophysical costs................ -- 1,362 5,953 3,692 3,779
Capitalized interest and general and
administrative costs.......................... -- 660 4,476 1,878 2,699
Other capital costs............................. -- 1,449 5,386 2,155 7,889
-------- ------- ------- ------- -------
$123,600 $74,477 $73,652 $44,770 $64,771
======== ======= ======= ======= =======
</TABLE>
A primary component of the Company's strategy is to continue its
exploration and development activities. The Company intends to finance capital
expenditures related to this strategy primarily with funds provided by
operations and borrowings under the Revolving Credit Facility. During the six
months ended June 30, 1996, the Company spent $47.1 million on exploration and
development drilling and $3.8 million on 3-D seismic surveys and other
geological and geophysical costs. Included in other capital costs for the six
months ended June 30, 1996, is $6.6 million, which relates primarily to capital
costs incurred on production facilities and flowlines. The Company is also a
party to two escrow agreements which provide for the future plugging and
abandonment costs associated with oil and gas properties. The first agreement,
related to East Bay, requires monthly deposits of $100,000 through June 30,
1998, and $350,000 thereafter until the balance in the escrow account equals $40
million, unless the Company commits to the plug and abandonment of a certain
number of wells in which case the increase will be deferred. The second
agreement, related to Main Pass 69, required an initial deposit of $250,000 and
monthly deposits thereafter of $50,000 until the balance in the escrow account
equals $7,500,000. As of June 30, 1996, the escrow balances totaled $5.3
million.
In addition to developing its existing reserves, the Company attempts to
increase its reserve base, production and operating cash flow by engaging in
strategic acquisitions of oil and gas properties. The Company intends to utilize
up to $117 million of the net proceeds from the Notes Offering to fund the
Central Gulf Acquisition. In order to finance any other possible future
acquisitions, the Company may seek to obtain additional debt or equity
financing. The availability and attractiveness of these sources of financing
will depend upon a number of factors, some of which will relate to the financial
condition and performance of the Company, and some of which will be beyond the
Company's control, such as prevailing interest rates, oil and gas prices and
other market conditions. There can be no assurance that the Company will acquire
any additional producing properties. In addition, the ability of the Company to
incur additional indebtedness and grant security interests with respect thereto
will be subject to the terms of the Existing Indenture and the Indenture.
The Company's other primary capital requirements for the remainder of 1996
will be for the Central Gulf Acquisition and the remaining $62 million of its
$124 million 1996 direct capital expenditure budget. The Company expects to fund
its obligations with proceeds of the Notes Offering, borrowings under the
Revolving Credit Facility and operating cash flow.
Liquidity. The ability of the Company to satisfy its obligations and fund
planned capital expenditures will be dependent upon its future performance,
which will be subject to prevailing economic conditions, including oil and gas
prices, and to financial and business conditions and other factors, many of
which are
38
<PAGE> 39
beyond its control, supplemented if necessary with existing cash balances and
borrowings under the Revolving Credit Facility. The Company expects that its
cash flow from operations, availability under the Revolving Credit Facility and
net proceeds from the Notes Offering will be adequate to execute its 1996
business plan. However, no assurance can be given that the Company will not
experience liquidity problems from time to time in the future or on a long-term
basis. If the Company's cash flow from operations and availability under the
Revolving Credit Facility are not sufficient to satisfy its cash requirements,
there can be no assurance that additional debt or equity financing will be
available to meet its requirements.
The Revolving Credit Facility has a borrowing base of $50 million. The
lenders may redetermine the borrowing base at their option once within any
12-month period as well as on scheduled redetermination dates as outlined in the
Revolving Credit Facility. The borrowing base automatically reduces by an amount
equal to one-sixteenth (1/16) of the borrowing base in effect on March 30,
1997, and continues to reduce at each quarter end beginning March 31, 1997,
unless the Company requests and is granted a one-year deferral of such
reductions.
The Company's ability to draw additional amounts on the Revolving Credit
Facility is limited to the extent that adjusted consolidated net tangible assets
(as defined) minus certain net production revenue (as defined) exceeds 110% of
all indenture indebtedness (as defined). Adjusted consolidated net tangible
assets is determined quarterly, utilizing certain financial information, and is
primarily based on a quarterly estimate of the present value of future net
revenues of the Company's proved oil and gas reserves. Such quarterly estimates
utilize the most recent year end oil and gas prices and vary based on additions
to proved reserves and net production. As of August 15, 1996, the Company's
outstanding balance on its Revolving Credit Facility was $28.5 million,
including $2.0 million which represented a letter of credit associated with
future abandonment obligations. The Company had remaining availability of $21.5
million under the Revolving Credit Facility as of August 15, 1996.
The Company recently conducted a consent solicitation with respect to the
Senior Notes to increase its ability to borrow under a revolving credit facility
from $50 million to the greater of (i) $50 million and (ii) $20 million plus 20%
of adjusted consolidated net tangible assets (as defined in the Existing
Indenture). As a result, the Company may seek to increase the borrowing base
under the Revolving Credit Facility.
Effects of Leverage. The Company is highly leveraged with outstanding
indebtedness of approximately $128 million as of June 30, 1996 ($284 million
upon giving pro forma effect to the Notes Offering and the application of the
net proceeds therefrom). The Company's level of indebtedness has several
important effects on its future operations, including (i) a substantial portion
of the Company's cash flow from operations must be dedicated to the payment of
interest on its indebtedness and will not be available for other purposes, (ii)
the covenants contained in the Existing Indenture require the Company to meet
certain financial tests, and the Existing Indenture contains and the Indenture
will contain restrictions which limit the Company's ability to borrow additional
funds or to dispose of assets and may affect the Company's flexibility in
planning for, and reacting to, changes in its business, including possible
acquisition activities and (iii) the Company's ability to obtain additional
financing in the future for working capital, expenditures, acquisitions, general
corporate purposes or other purposes may be impaired.
Pursuant to the Existing Indenture, the Company may not incur any
indebtedness other than permitted indebtedness (as defined in the Existing
Indenture) unless the Company's consolidated fixed charge coverage ratio (as
defined in the Existing Indenture) for the four full fiscal quarters preceding
the proposed new indebtedness is greater than 2.75 to 1.0 (3.0 to 1.0 if the
indebtedness is incurred after December 1, 1997) after giving pro forma effect
to the proposed new indebtedness, the application of such indebtedness and other
significant transactions during the period. In addition, the Company's adjusted
consolidated net tangible assets (as defined in the Existing Indenture) must be
greater than 150% of indebtedness after giving effect to the incurrence of the
proposed new indebtedness and related transactions. The Indenture is expected to
contain a provision requiring a consolidated fixed charge coverage ratio of 2.5
to 1.0, but is not expected to contain a provision requiring maintenance of a
specified level of adjusted consolidated net tangible assets. As of June 30,
1996, the Company's consolidated fixed charge coverage ratio was 5.1 to 1.0 for
the preceding four quarters, and its adjusted consolidated net tangible assets
were 211% of indebtedness. After giving pro forma effect to
39
<PAGE> 40
the Notes Offering and the application of the net proceeds therefrom, the
Company estimates that its adjusted consolidated net tangible assets would have
been 154% of indebtedness as of June 30, 1996. If the ratio of adjusted
consolidated net tangible assets to indebtedness falls below 110%, the Company
may be required to buy back a portion of the Senior Notes.
In accordance with the terms of the Existing Indenture, if the Company
disposes of oil and gas assets, it must apply such proceeds to permanently pay
down indebtedness other than the Senior Notes or within 270 days of the asset
sale, purchase additional oil and gas properties to replace the properties sold.
If proceeds not applied as indicated above exceed $10 million, the Company would
be required to offer to purchase outstanding Senior Notes or other pari passu
indebtedness in an amount equal to the unapplied proceeds. The Indenture is
expected to contain a similar, but more flexible provision. See "Description of
the Notes."
The Company's ability to meet its debt service obligations and to reduce
its total indebtedness will be dependent upon the Company's future performance,
which will be subject to oil and gas prices, general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. There can be no assurance that the
Company's future performance will not be adversely affected by such economic
conditions and financial, business and other factors. See "Risk Factors -- Price
Fluctuations and Markets" and "Capitalization."
OTHER MATTERS
Energy swap agreements. On June 30, 1993, the Company entered into a
Master Energy Price Swap Agreement (the "Swap Agreement") with Enron Capital &
Trade Resources Corp. ("ECT"), pursuant to which the Company and ECT enter into
energy price swap arrangements from time to time. These arrangements obligate
the Company or ECT to make payments to the other at the end of a determination
period based on the difference between a specified fixed price and an average of
floating prices over the determination period, applied to a specified quantity
of crude oil or natural gas. All of the Company's currently outstanding swap
arrangements use a floating price for crude oil based on NYMEX light sweet crude
oil futures contracts. Under the terms of the Swap Agreement, if the Company's
net exposure exceeds $5.0 million, ECT can require the Company to establish and
maintain a letter of credit for the amount of such excess, rounded up to the
next multiple of $500,000. Net exposure is based upon the amount by which the
Company's payment obligations to ECT under energy price swap arrangements under
the Swap Agreement exceed the payment obligations of ECT to the Company under
such arrangements. As of August 2, 1996, the Company's net exposure to ECT under
all contracts covered by the Swap Agreement was approximately $2.9 million.
As of June 30, 1996, the Company's open forward position was as follows:
<TABLE>
<CAPTION>
OIL GAS
---------------------- ----------------------
AVERAGE AVERAGE
YEAR MBBLS PRICE BBTU PRICE
- -------------------------------------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C>
1996........................................ 1,550 $ 18.25 1,230 $ 1.97
1997........................................ 300 18.55 -- --
1998........................................ 300 18.55 -- --
1999........................................ 300 18.55 -- --
2000........................................ 300 18.55 -- --
----- ------ ----- -----
Total.................................. 2,750 $ 18.38 1,230 $ 1.97
===== ====== ===== =====
</TABLE>
As a result of hedging activity under the Swap Agreement, on a BOE basis,
the Company estimates that 36% of its estimated remaining 1996 production which
is classified as proved reserves as of June 30, 1996, will not be subject to
price fluctuation for 1996.
40
<PAGE> 41
Currently, it is the Company's intention to commit no more than 50% of its
total annual production on a BOE basis to such arrangements. Moreover, under the
Revolving Credit Facility, the Company is prohibited from committing more than
75% of its production estimates for the next 24 months to such arrangements at
any point in time. As the current swap agreements expire, the portion of the
Company's oil and natural gas production which is subject to price fluctuations
will increase significantly, unless the Company enters into additional hedging
transactions.
Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas and oil sold
in the spot market. Prices received for natural gas sold on the spot market are
volatile due primarily to seasonality of demand and other factors beyond the
Company's control. Domestic oil prices generally follow worldwide oil prices
which are subject to price fluctuations resulting from changes in world supply
and demand. While the price the Company receives for its oil and natural gas
production has significant financial impact on the Company, no prediction can be
made as to what price the Company will receive for its oil and natural gas
production in the future.
Gas balancing. It is customary in the industry for various working
interest partners to produce more or less than their entitlement share of
natural gas from time to time. The Company's net overproduced position decreased
from 1,080,726 Mcf at December 31, 1995, to 1,014,884 Mcf at June 30, 1996.
Under the provisions of the applicable gas balancing agreement, the
underproduced party can take up to 50% of the Company's entitled share of gas
production in future months to eliminate the imbalance. During the make-up
period, the Company's gas revenues will be adversely affected, minimized by an
unjust enrichment clause contained in the gas balancing agreement. The Company
recognizes revenue and imbalance obligations under the sales method of
accounting.
Environmental. The Company's business is subject to certain federal,
state, and local laws and regulations relating to the exploration for, and the
development production and transportation of, oil and natural gas, as well as
environmental and safety matters. Many of these laws and regulations have become
more stringent in recent years, often imposing greater liability on a larger
number of potentially responsible parties. Although the Company believes it is
in substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations are frequently changed and
subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations.
Under certain circumstances, the MMS may require any Company operations on
federal leases to be suspended or terminated. Any such suspensions, terminations
or inability to meet applicable bonding requirements could materially and
adversely affect the Company's financial condition and operations. Although
significant expenditures may be required to comply with governmental laws and
regulations applicable to the Company, to date such compliance has not had a
material adverse effect on the earnings or competitive position of the Company.
It is possible that such regulations in the future may add to the cost of
operating offshore drilling equipment or may significantly limit drilling
activity. See "Business and Properties -- Governmental Regulation,"
"-- Environmental Matters" and "-- Abandonment Costs."
On August 25, 1993, the MMS published an advance notice of its intention to
adopt regulations under the Oil Pollution Act of 1990 that would require owners
and operators of offshore oil and natural gas facilities to establish $150
million in financial responsibility in case of a potential spill. In November
1995, the U.S. Senate approved a bill that would amend OPA 90 to reduce the
level of financial responsibility to $35 million. The U.S. House of
Representatives passed an amended version of the U.S. Senate bill on February
29, 1996. The measure is now before a joint congressional conference. The
Clinton Administration has expressed its support for this legislation. The MMS
has indicated that it would not move forward with the adoption of its proposed
rule until the United States Congress has had an opportunity to act on the
matter. Based on the passage of these bills and the support of the Clinton
Administration, it appears that the level of financial responsibility required
under OPA 90 will be reduced. The impact of the regulations, however, should not
be any more adverse to the Company than they will be to other similarly situated
owners or operators in the Gulf of Mexico region.
41
<PAGE> 42
BUSINESS AND PROPERTIES
GENERAL
The Company is an independent energy company engaged in the acquisition,
exploration, development and production of crude oil and natural gas with
operations focused primarily in the Louisiana Gulf. As of June 30, 1996, the
Company had estimated proved reserves of approximately 36.7 MMBbls of oil and
44.1 Bcf of natural gas, or an aggregate of 44.0 MMBOE with a Present Value of
Future Net Revenues of $279.0 million and a Standardized Measure of Discounted
Future Net Cash Flows of approximately $238.2 million, of which approximately
89% are classified as proved developed.
RECENT DEVELOPMENTS
On July 10, 1996, the Company entered into a Purchase and Sale Agreement
with Mobil to acquire interests in certain oil and gas producing fields and
related production facilities primarily situated in the shallow waters of the
Central Gulf of Mexico, offshore Louisiana, for an anticipated net purchase
price of approximately $117 million (subject to reduction to as low as $113
million if certain preferential purchase rights of third parties on portions of
the properties are exercised). Subject to assignment of the applicable operating
agreements, the Company anticipates that it will become the operator of
approximately 75% of the properties. As of June 30, 1996, the Central Gulf
Properties had estimated proved reserves of approximately 13.8 MMBbls of oil and
50.8 Bcf of natural gas, or an aggregate of approximately 22.3 MMBOE, with a
Present Value of Future Net Revenues of approximately $147.0 million and a
Standardized Measure of Discounted Future Net Cash Flows of approximately $113.4
million. For the six months ended June 30, 1996, estimated average net daily
production on the Central Gulf Properties was approximately 4,800 Bbls of oil
and 27,500 Mcf of natural gas from approximately 125 producing wells on 87,514
gross (49,248 net) acres. Pro forma for the Central Gulf Acquisition, the
Company's average daily production is expected to increase by approximately 30%,
and its proved reserve mix is expected to shift to approximately 76% oil and 24%
gas from the current mix of 83% oil and 17% gas. The closing of the Central Gulf
Acquisition is expected to occur concurrently with the consummation of the Notes
Offering, subject to approvals by the management and Board of Directors of Mobil
and the Company, and subject to the aforementioned preferential purchase rights.
The Central Gulf Acquisition will allow the Company to significantly expand
its primary operations by establishing a new core area in the central Louisiana
Gulf region while acquiring properties which it believes are complementary to
its existing asset base. The Central Gulf Properties represent a large acreage
acquisition in proximity to properties with prolific production histories. The
Company believes the Central Gulf Properties have substantial similarities with
its existing Main Pass and East Bay Fields, including a significant proven
reserve base with large exploitation and exploration potential resulting from
the Company's utilization of recently acquired 3-D seismic data. The Company
therefore expects to maximize the value of the Central Gulf Properties by
utilizing exploration, exploitation and development techniques similar to those
employed on its existing properties. The Company has already identified over 150
drilling prospects on the Central Gulf Properties that it intends to pursue.
Also, the Company believes that it will be able to integrate the Central Gulf
Properties into its existing corporate infrastructure, which should result in
future economies of scale and enhanced cash flow.
STRENGTHS
The Company believes it has unique strengths that position it to continue
as a successful independent operator in the Louisiana Gulf, including the
following:
Quality of existing operations. The East Bay Fields and Main Pass 69 are
three of the 20 most productive fields in the Gulf of Mexico based on total
historical production. These fields have extensive production histories and
contain significant reserve and production enhancement opportunities. Production
from the East Bay Fields and Main Pass 69 has been predominantly from the upper
10,000 feet of sediment. While cumulative historical production from these
horizons has exceeded one billion BOE, the Company believes that potential may
exist for additional reserves to be found at these horizons, as well as deeper
horizons. As of August 9, 1996, the Company's existing properties collectively
comprised over 63,982 net acres
42
<PAGE> 43
of Louisiana state and federal offshore leases (42,248 of which are held by
production), including 15,707 net lease acres which were acquired by the Company
during the first six months of 1996 for exploratory purposes, a large portion of
which are adjacent to its producing leases.
Extensive technological database. As of August 8, 1996, the Company owned
approximately 516 square miles of 3-D seismic data and over 20,000 linear miles
of 2-D seismic data in and around its core properties. In addition, the Company
is nearing completion of a 70 square mile 3-D seismic survey covering Main Pass
69 as well as a 70 square mile survey covering Mallard Bay. These surveys are
expected to be completed by the end of September, 1996. Additionally, to
complement the Central Gulf Acquisition, the Company has acquired approximately
191 square miles of 3-D seismic data covering the Central Gulf Properties and
surrounding acreage. F&R uses state-of-the-art seismic evaluation technology in
its exploitation and exploration activities in order to reduce risks and lower
drilling costs. The seismic evaluation technology is integrated with subsurface
data to improve the Company's ability to properly define the structural and
stratigraphic features which potentially contain accumulations of hydrocarbons.
The Company employs 19 geoscientists to integrate and evaluate its expansive
seismic data base. Management believes the availability of 3-D seismic coverage
for the Gulf of Mexico at reasonable costs enhances the potential for returns on
exploration and development activities in the area.
Efficient operator. The Company is a 100% working interest owner and
operator of virtually all of its existing wells, allowing it to control
expenses, capital allocation and the timing of development and exploitation of
its fields. Since 1992, the Company has decreased lease operating expenses by
28%, from $5.45 per BOE for the period from inception (April 20, 1992) through
December 31, 1992 to $3.95 per BOE for the six months ended June 30, 1996. Prior
to the Company's ownership, lease operating expenses at the East Bay Complex in
1989, 1990, and 1991 were $8.15, $10.58, and $9.74, respectively, per BOE and
lease operating expenses at Main Pass 69 in 1989, 1990 and 1991 were $6.59,
$11.33 and $8.17, respectively, per BOE.
Expertise in the Louisiana Gulf. Management believes the Company's
existing asset base and personnel provide it with competitive advantages for
operating in the Louisiana Gulf. The Company's senior operating personnel as
well as its 19 geoscientists and 17 petroleum engineers have substantial
experience, largely through tenure at major oil companies, in the technical
challenges arising from exploitation and exploration of this region. The Company
has also assembled a team of field personnel, most with over 15 years of
experience in operating the East Bay Complex, Main Pass 69 or other large
properties in the Louisiana Gulf. Management has extensive experience and good
working relationships with federal, state and local regulatory agencies in this
region.
Expandable base of operations. The Company has additional capacity
available at its East Bay Complex and Main Pass 69 production facilities, which
can provide a foundation for further acquisition, exploitation and exploration
in the Louisiana Gulf to achieve additional production at relatively low
incremental costs. Because of the strategic location of the East Bay Facilities
between extensive offshore production and onshore processing and transmission
facilities, the excess capacity can also be used to provide services to third
parties operating in the area. The Company also believes that its operating and
administrative personnel and systems can efficiently manage the addition of
producing properties and related operations through geographic concentration,
technical expertise and economies of scale based on existing infrastructure and
the maintenance of low overhead costs.
BUSINESS STRATEGY
The Company's strategy is to increase value by increasing its reserve base
and by continuing to decrease unit costs. The Company intends to grow its oil
and gas reserves by capitalizing on its strengths through the exploitation of
its existing properties, the exploration for new oil and gas reserves on its
existing properties and elsewhere and the acquisition of additional properties
with exploitation and exploration potential. The Company intends to decrease
unit costs by streamlining existing operations and increasing production. The
Company is implementing this strategy by:
Continuing development and exploitation of existing properties. The Company
is actively pursuing the development of its existing properties to fully exploit
its reserves through recompletions, horizontal and
43
<PAGE> 44
development drilling, waterfloods and 3-D seismic enhanced exploitation
drilling. F&R uses advanced technology in its exploitation and exploration
activities in order to reduce risks and lower costs. Further, the Company seeks
to drill wells with multiple pay objectives, allowing it to reduce the risk of
exploring deeper prospects by attempting to exploit shallow reservoirs in the
same well. Primarily as a result of its development and exploitation drilling
success, the Company has increased its average daily production by 59% from
15,047 BOE for the year ended December 31, 1994 to 23,862 BOE for the twelve
months ended June 30, 1996. Since August 1, 1996, the Company's average daily
production has exceeded 30,000 BOE. The Company currently has an inventory of
over 330 reserve and production enhancement projects on its existing properties.
In light of these projects, the Company plans to increase its development and
exploitation capital drilling expenditures from approximately $22 million in
1994 and $42 million in 1995, to a budgeted amount of approximately $66 million
for 1996.
Expanding exploration program. The Company is expanding its exploration
program in the Louisiana Gulf which is designed to provide exposure to selected
higher risk, higher potential rate of return prospects. The Company expects to
increase its exploratory drilling expenditures from approximately $12 million in
1995 (22% of an approximate $55 million drilling budget) to approximately $26
million in 1996 (28% of an approximate $92 million drilling budget), with
further increases possible. In order to reduce exploration risk, the Company
will apply state-of-the-art technology to identify prospects and, where
possible, select well locations with multiple pay objectives. The Company
believes the seismic database and operating experience derived from its existing
properties provide it with a competitive advantage in evaluating new prospects
on properties sharing the same or similar geologic characteristics. The Company
utilizes these assets and its experience to identify and acquire new leasehold
acreage and existing producing properties that it believes contain significant
exploration potential. In the first six months of 1996, the Company acquired
42,651 net acres of seismic options and oil and gas leases, a large portion of
which are located adjacent to its producing leases, including seismic and lease
options covering 26,945 acres in Cameron Parish, Louisiana. Based upon
preliminary evaluation of seismic data prior to acquisition of these leases and
options, the Company believes it has significantly enhanced its inventory of
prospects.
Pursuing strategic acquisitions. The Company is continually evaluating
opportunities to acquire producing properties which may possess, among others,
one or more of the following characteristics: (i) potential for increases in
reserves and production through exploration and exploitation drilling, (ii)
proximity to the Company's existing operations, or (iii) potential opportunities
to reduce expenses through more efficient operations. While the Company focuses
primarily on the acquisition of producing properties involving large acreage
positions, it evaluates a broad range of potential transactions. Company
personnel have substantial training, experience, and an in-depth knowledge of
the Louisiana Gulf area, as well as established relationships with a number of
major and large independent energy companies operating in this region. These
factors, in combination with state-of-the-art geological and engineering
technology, assist in identifying properties that meet the Company's acquisition
objectives.
44
<PAGE> 45
SUMMARY PROJECT INVENTORY FOR EXISTING PROPERTIES
Consistent with the drilling strategies discussed above, set forth below is
a summary of the Company's current inventory of reserve and production
enhancement projects on its existing properties. While the Company presently
intends to complete these projects, the number, type and timing of the proposed
projects are subject to continued revision as a result of many factors,
including the availability of capital to fund such projects, initial test
results, the price of oil and gas, weather and other general and economic
conditions. The Company currently has budgeted approximately $62 million of its
$124 million direct capital expenditure budget for 1996 to apply towards a
portion of the following projects on its existing properties.
<TABLE>
<CAPTION>
NUMBER OF
TYPE OF PROJECT PROJECTS
-------------------------------------------------------------- ---------
<S> <C>
Recompletion/Workovers........................................ 158
Waterfloods................................................... 9
Development Drilling.......................................... 74
Horizontal Drilling........................................... 14
"Develocat" Drilling.......................................... 36
Exploration Drilling.......................................... 42
---
Total....................................................... 333
===
</TABLE>
Recompletions. A recompletion involves the completion of an existing well
bore in a formation other than one which has previously been productive.
Existing wellbores on the Company's properties have numerous recompletion
opportunities and are an important part of the Company's proved reserve base.
The Company uses the latest completion techniques to effect high productivity
recompletions. A recent dual recompletion was the SL 1012 #323 which initially
tested at a combined rate of 1,104 BOPD and 1,570 MCFPD from the K2L and H2
zones.
Waterfloods. A waterflood is the injection of water into a reservoir to
fill pores vacated by produced fluids, thus maintaining reservoir pressure,
assisting production and enhancing reservoir recovery rates. The Company
currently operates 34 waterfloods and has identified 9 potential waterflood
projects.
Development Drilling. Development drilling involves wells drilled within
the proved area of an oil or gas reservoir to a zone known to be productive.
Studies in certain areas on the existing properties have revealed significant
reservoir extension opportunities and in-fill drilling locations in existing
reservoirs. For example, in 1996 the Company successfully drilled the "Oiler
Prospect", State Lease 1388 #B74, which initially tested the So and Tl sands for
a combined rate of approximately 1,271 BOPD and 1,057 MCFPD.
Horizontal Drilling. Horizontal drilling permits the operator to contact
and intersect a larger portion of the producing horizon than conventional
vertical drilling techniques and can result in both increased production rates
and greater ultimate recoveries of hydrocarbons. The Company has identified
several reservoirs which have low relief structural or bottom water drive
characteristics that can be more economically produced with horizontal well
completions. For example, in 1996, the Company's Cypress 3 horizontal well, the
State Lease 1007 #55, was completed in the "K" sand and is currently producing
in excess of 5,000 BOE per day.
"Develocat" Drilling. Develocat drilling involves evaluating deeper
untested sands classified as exploratory while developing a shallower known
reservoir. The Company attempts to access stacked pays and multiple reservoirs
from a single well bore in order to reduce risk for deeper objectives by
providing alternative uphole reserves. For example, in 1996 the Company
successfully drilled its Cypress 2 prospect, the State Lease 1007 #52 well,
which initially tested at a combined rate of 1,689 BOPD and 709 MCFPD from the J
and K1 sands.
Exploration Drilling. Exploratory wells are drilled to find and produce
oil or gas reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir or to
extend a known reservoir. The Company conducts a controlled exploration program
in the Louisiana Gulf which is designed to provide exposure to selected higher
risk, higher potential rate of return prospects. The
45
<PAGE> 46
Company manages its exploration risks by limiting its exploration expenditures,
applying state-of-the-art technology such as 3-D seismic surveys to identify
prospects and, where possible, selecting well locations with multiple-pay
objectives. In addition, the Company would consider, in selected circumstances,
selling a portion of a prospect to an industry partner while preferably
remaining as operator. Utilizing 3-D seismic data, the Company in 1996
successfully drilled the OCS 693 #11 well on its "Aladdin Prospect" which
initially tested at a rate of 10,768 MCFPD.
The following opportunities are representative of the type of exploration
projects the Company is currently pursuing:
The Grand Isle Block 68 "Highside" prospect is named for the producing trap
style of the project. The test well will evaluate prospective sands beginning at
6,000 feet and continuing to 13,000 feet. The directional well will attempt to
follow the high side of a regionally productive down-to-the-north fault system
which has been proven productive above 6,000 feet on offsetting acreage.
The "Catapult" prospect is located in West Delta Block 55 just west of the
Company's East Bay Fields. The test well is designed to evaluate two primary
objectives in the geopressured section from 12,000-14,000 feet. The trap at the
shallower LF Sand level is a downthrown closure with additional trapping
provided by a smaller antithetic fault. The deeper Lower OG objective is
stratigraphically trapped on the same large fault system. Both prospective sands
have production analogies in adjacent fields.
Two high potential projects have been identified on the Company's newly
acquired federal lease covering Main Pass Block 138. The Company has acquired a
new 3-D seismic survey that has helped identify numerous bypassed or unevaluated
prospects on the block. The "Vision" prospect targets multiple stacked shallow
Pliocene Sands on the upthrown side of a growth fault. The "Phase" prospect will
test a deep-seated four-way closure in the Miocene Cib Carst sands updip to
hydrocarbon shows on the block as well as shallower amplitude anomalies.
Matterhorn, a deep lateral salt and subsalt exploration prospect, underlies
the Company's producing acreage in South Pass 27 Field. Production to date has
largely been from shallow sands overlying the salt mass, with very little
drilling having been directed to deeper salt-sediment traps. The Company is
currently reprocessing its seismic data using pre-stack time and post-stack
depth migration and AVO analysis to further evaluate the deeper horizons lying
beneath the salt mass.
The Company has recently extended its operations in the Louisiana Gulf to
include several coastal onshore exploration prospects since the Company believes
this region has been underexplored due to its complex geology and lack of 3-D
seismic data. Advances in 3-D seismic acquisition techniques over the past few
years have led the Company to purchase options to conduct a 3-D seismic survey
and explore for oil and gas on 26,945 acres in eastern Cameron Parish,
Louisiana. The Company is currently conducting a 70 square mile proprietary 3-D
seismic survey over Mallard Bay along with its 50% working interest partner,
Mobil. Over 70 prospects or leads have been identified on Mallard Bay from
review of 2-D seismic and subsurface data.
Separately, the Company recently acquired seismic and lease options
covering 14,060 acres in the Lacassine area located approximately 6 miles
northwest of Mallard Bay which it expects to develop on its own in 1997. The
Company expects to conduct a proprietary 3-D seismic survey over the approximate
25 square mile Lacassine area situated east of the prolific Chalkley Field
complex (with cumulative production of over 430 BCFGE) and west of the South
Thornwell/Lakeside Field complex (with cumulative production of over 966 BCFGE),
areas of multiple stacked Oligocene age pays. Prospects have been identified
which offset shows or pays in major producing sands in the area. They are
trapped by regional down-to-the-south faulting with further complication by
ancillary faults, which is a typical trap style for the area. An existing 3-D
survey has partially validated a portion of the prospect area with further
seismic verification expected to result from the planned seismic survey.
46
<PAGE> 47
PROPERTIES
Main Pass 69
The Company owns an average 97.6% working interest in the Main Pass 69
field. The Company's interest in Main Pass 69, which includes the Company's
interest in the adjacent South Pass One field, consists of 67 producing wells
located on approximately 16,058 gross leased acres in state waters 70 miles
southeast of New Orleans, Louisiana. The field was discovered in 1948, and has
pay sands ranging in age from Pliocene to upper Miocene, with the bulk of
production historically coming from the Pliocene. For the three months ended
June 30, 1996, the Company's average daily sales at Main Pass 69 were 3,035 Bbls
of oil and 4,656 Mcf of gas. As of June 30, 1996, Main Pass 69 had proved
reserves of 6.6 MMBbls of oil and 5.3 Bcf of natural gas.
The Main Pass 69 field includes onshore and offshore facilities located in
Plaquemines Parish, Louisiana. The onshore facilities are located on the north
bank of Pass-A-Loutre, bounded by the Gulf of Mexico to the north. The offshore
facilities, which include wells, production platforms and related structures,
extend northwest approximately seven miles from marshes adjacent to the banks of
Pass-A-Loutre into water depths of approximately 15 feet in the open water
areas.
Main Pass 69 has five production platforms and one waterflood platform.
These platforms each contain separators, tanks and manifolds. Most of the wells
in Main Pass 69 are on gas lift or are within one of the active waterflood
projects. Main Pass 69 also contains a central facility located one mile south
of the field on the north bank of the North Pass of Pass-A-Loutre. The facility
contains oil storage tanks, crude oil transportation facilities, living
quarters, a warehouse, a loading dock, a boat maintenance shop, a floating plane
dock and administrative offices. The central facility is the control center for
the Main Pass 69 properties and provides a support base for the entire field
operation. Based on the excess oil storage and production capacity, and its
proximity to an existing oil pipeline system, the central facility is able to
accept increased production from internal as well as external sources.
East Bay Complex
The Company owns an average 99.1% working interest in the East Bay fields.
The East Bay Complex consists of 428 producing wells located on approximately
31,598 gross leased acres and onshore and offshore facilities in Plaquemines
Parish, Louisiana and adjacent federal waters. The South Pass 24 field was
discovered in 1950 and the South Pass 27 field was discovered in 1954. Both
fields have sands that range in age from Pliocene to Miocene. Production has
been established from 40 horizons comprising 240 reservoirs from the South Pass
24 field and 51 horizons comprising 460 reservoirs from the South Pass 27 field.
For the three months ended June 30, 1996, the Company's average total daily
sales at the East Bay Complex were 12,895 Bbls of oil and 35,837 Mcf of gas. As
of June 30, 1996, the East Bay Complex had proved reserves of 29.8 MMBbls of oil
and 35.2 Bcf of natural gas.
The offshore facilities, which include wells and related structures, extend
southeasterly approximately seven miles from marshes adjacent to the East Bay
facilities into water depths of up to 80 feet in the State of Louisiana and
federal waters of the Gulf of Mexico. The major offshore facilities consist of
over 630 well jackets with 980 well slots and major structures such as manifold,
production and waterflood platforms. Approximately 95% of the active producing
wells require gas lift.
The onshore facilities are located on the east bank of the Southwest Pass
of the Mississippi River and are bounded by the Mississippi River on the west
and the Gulf of Mexico on the east. The major onshore facilities consist of oil
processing facilities with capacity for 70 MBbls per day, a crude oil storage
tank battery, a produced water treatment plant, gas compression and dehydration
facilities with a capacity of 240 MMcf per day, living quarters, an electric
power generator, instrument air systems, sewage disposal, a boat maintenance
shop, a heliport, a floating plane dock and a loading dock.
The gas compression system is comprised of 21 compressors totaling 63,000
horsepower for gas lift operations and sales. Maximum compressor capacity is 250
MMcf per day. Four stages of compression are used to compress produced gas from
45 psig to about 1,400 psig. The compression system generally maintains an
onshore suction header pressure of about 45 psig and a fourth stage discharge
header pressure of between
47
<PAGE> 48
1,300 to 1,400 psig required for offshore gas lift. Gas not required for gas
lift is sold from the third stage discharge header. The average daily gas flow
rate to supply the gas lift system is approximately 170 MMcf per day.
All gas sold or used for gas lifting is processed through a dehydration
system to less than six pounds of water content per Mcf of gas. Three glycol
dehydration units provide a capacity of 250 MMcf per day for gas dehydration.
Oil from three offshore free water knock out ("FWKO") platforms is received
at the oil processing and storage battery. The oil processing facility consists
of three 20,000 barrel stock tanks, two 10,000 barrel cylinder tanks and various
oil and water transfer pumps.
The produced water treating plant facility was built in 1990. The facility,
which receives produced water from the offshore FWKO platforms and the oil
processing facility, skims and cleans produced formation water at a capacity up
to 240 MBbls of water per day.
The maintenance and utilities facilities include instrument air systems,
utility and fire control water facilities, a sewage treatment plant and electric
power generation. Electrical power for the entire central facility is provided
by four electromotive diesel 1,450 horsepower engines each with 1,000 kilowatt
generators.
OIL AND NATURAL GAS RESERVES
Presented below are the estimated quantities of proved developed and proved
undeveloped reserves of crude oil and natural gas, the Estimated Future net
revenues (before income taxes), the Present Value of Future Net Revenues (before
income taxes) and the Standardized Measure of Discounted Future Net Cash Flows
as of June 30, 1996. Information with respect to the Company's existing
properties was prepared by the Company's engineers in accordance with the rules
and regulations of the Commission; however, such reserve information has not
been reviewed by independent reserve engineers. In accordance with rules and
regulations of the Commission, the pre-tax estimated future net revenues,
pre-tax present value of future net revenues and the Standardized Measure of
Discounted Future Net Cash Flows prepared by the Company have been decreased by
approximately $7,595,000, $6,861,000 and $4,596,000, respectively, representing
the effect of hedging transactions entered into as of June 30, 1996. The
information with respect to the Central Gulf Properties has been estimated by
the Company.
<TABLE>
<CAPTION>
JUNE 30, 1996
PROVED RESERVES
---------------------------------------------------------------------------------
CENTRAL CENTRAL CENTRAL
GULF GULF GULF PRO
COMPANY COMPANY COMPANY PROPERTIES PROPERTIES PROPERTIES FORMA
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL COMBINED(2)
--------- ----------- -------- --------- ----------- ---------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Net Proved Reserves:
Oil (MBbls).................. 32,463 4,233 36,696 9,148 4,659 13,807 50,503
Gas (MMcf)................... 41,397 2,681 44,078 31,462 19,345 50,807 94,885
MBOE (6 Mcf per Bbl)......... 39,362 4,680 44,042 14,392 7,883 22,275 66,317
Estimated Future Net Revenues
(Before Income Taxes)........ $306,082 $36,996 $343,078 $103,993 $86,966 $190,959 $ 534,037
Present Value of Future Net
Revenues (Before Income
Taxes; Discounted at 10%).... $251,515 $27,508 $279,023 $ 89,773 $57,265 $147,038 $ 426,061
Standardized Measure of
Discounted Future Net Cash
Flows(1)..................... $238,161 $113,370 $ 351,531
</TABLE>
- ---------------
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by the
Company represents the Present Value of Future Net Revenues after income
taxes discounted at 10%.
(2) If the preferential purchase rights with respect to the Central Gulf
Acquisition are exercised in full the pro forma net proved reserves, the
Present Value of Future Net Revenues and the Standardized Measure of
Discounted Future Net Cash Flows would be 65,333 MBOE, $421,006,000 and
$347,219,000, respectively.
48
<PAGE> 49
Presented below are the estimated quantities of proved developed and proved
undeveloped reserves of crude oil and natural gas, the Estimated Future Net
Revenues (before income taxes), the Present Value of Future Net Revenues (before
income taxes) and the Standardized Measure of Discounted Future Net Cash Flows
for the Company as of December 31, 1995. Information set forth in the following
table is based upon reserve reports prepared by Netherland Sewell, independent
petroleum engineers, in accordance with the rules and regulations of the
Commission. In accordance with rules and regulations of the Commission, the
pre-tax estimated future net revenues, pre-tax present value of future net
revenues and the Standardized Measure of Discounted Future Net Cash Flows
prepared by the Company have been decreased by approximately $7,669,000,
$7,181,000 and $4,929,000, respectively, representing the effect of hedging
transactions entered into as of December 31, 1995.
<TABLE>
<CAPTION>
PROVED RESERVES AT DECEMBER 31, 1995
-----------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Net proved Reserves:
Oil (MBbls)................................ 23,588 8,114 2,127 33,829
Gas (MMcf)................................. 14,525 34,110 1,941 50,576
MBOE (6 Mcf per Bbl)....................... 26,008 13,799 2,451 42,258
Estimated Future Net Revenues (Before Income
Taxes)..................................... $ 144,062 $ 117,786 $17,982 $279,830
Present Value of Future Net Revenues (Before
Income Taxes; Discounted at 10%)........... $ 147,664 $ 76,216 $10,855 $234,735
Standardized Measure of Discounted Future Net
Cash Flows(1).............................. $203,940
</TABLE>
- ---------------
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by
the Company represents the Present Value of Future Net Revenues after
income taxes discounted at 10%.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
The quantities of oil and natural gas that are ultimately recovered, production
and operating costs, the amount and timing of future development expenditures
and future oil and natural gas sales prices may all differ from those assumed in
these estimates. Therefore, the Present Value of Future Net Revenues figures
shown above should not be construed as the current market value of the estimated
oil and natural gas reserves attributable to the Company's properties. The
information set forth in the foregoing tables includes revisions of certain
volumetric reserve estimates attributable to proved properties included in the
preceding year's estimates. Such revisions are the result of additional
information from subsequent completions and production history from the
properties involved or the result of a decrease (or increase) in the projected
economic life of such properties resulting from changes in product prices.
In accordance with the Commission's guidelines, the engineers' estimates of
future net revenues from the Company's properties and the Present Value of
Future Net Revenues thereof are made using oil and natural gas sales prices in
effect as of the dates of such estimates and are held constant throughout the
life of the properties except where such guidelines permit alternate treatment,
including the use of fixed and determinable contractual price escalations. The
prices as of June 30, 1996 were $19.53 per Bbl of crude oil and $2.58 per Mcf of
natural gas for the East Bay Complex and $20.62 per Bbl of crude oil and $2.63
per Mcf of natural gas for Main Pass 69. The prices as of December 31, 1995 were
$18.86 per Bbl of crude oil and $2.57 for Mcf of natural gas for the East Bay
Complex and $19.23 per Bbl of crude oil and $2.51 per Mcf of natural gas for
Main Pass 69. The foregoing prices exclude the effect of net price hedging
positions. Prices for natural gas and, to a lesser extent, oil are subject to
substantial seasonal fluctuations and prices for each are subject to
49
<PAGE> 50
substantial fluctuations as a result of numerous other factors. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "-- Oil and Gas Marketing and Major Customers."
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth the Company's existing productive wells as
of June 30, 1996:
<TABLE>
<CAPTION>
GROSS NET
----- ---
<S> <C> <C>
Oil....................................................... 488 470
Gas....................................................... 28 22
--- ---
Total Productive Wells.................................. 516 492
=== ===
</TABLE>
Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. Wells that are
completed in more than one producing horizon are counted as one well. Of the
gross wells reported above, 25 had multiple completions.
Acreage Data
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned. A net
acre is deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional interests
owned in gross acres expressed as whole numbers and fractions thereof. The
following table sets forth the approximate developed and undeveloped acreage in
which the Company held a leasehold mineral or other interest at June 30, 1996.
<TABLE>
<CAPTION>
UNDEVELOPED
DEVELOPED ACRES ACRES
---------------- ----------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Federal waters............................................ 4,330 4,330 9,995 7,495
State waters and onshore.................................. 43,997 37,918 16,403 14,240
------ ------ ------ ------
Total................................................... 48,327 42,248 26,398 21,735
====== ====== ====== ======
</TABLE>
In addition, the Company has acquired options covering 26,945 acres in
Cameron Parish, Louisiana, which allow the Company to conduct 3-D seismic
operations on Mallard Bay and to subsequently acquire oil and gas leases on such
acreage.
50
<PAGE> 51
DRILLING ACTIVITIES
The following table sets forth the drilling activity of the Company on its
properties for the period from April 20, 1992 (inception) through December 31,
1992, and for the years ended December 31, 1993, 1994 and 1995.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1992 1993 1994 1995
------------ ------------ ------------- ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive............................... 0 0 0 0 1 .88 1 1
Nonproductive............................ 0 0 0 0 1 .88 3 2
Development Wells:
Productive............................... 0 0 3 2.19 10 8.75 17 17
Nonproductive............................ 0 0 0 0 1 .43 0 0
---- ---- ---- ---- ---- ----- ---- ----
Total................................. 0 0 3 2.19 13 10.94 21 20
==== ==== ==== ==== ==== ===== ==== ====
</TABLE>
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to oil and
gas production and lease operating expenses attributable to all oil and gas
property interests owned by the Company for the period from April 20, 1992
(inception) through December 31, 1992, for the years ended December 31, 1993,
1994 and 1995 and for the six months ended June 30, 1995 and 1996.
<TABLE>
<CAPTION>
PERIOD FROM
INCEPTION
(APRIL 20, 1992) SIX MONTHS ENDED
THROUGH YEAR ENDED DECEMBER 31, JUNE 30,
DECEMBER 31, -------------------------- ----------------
1992 1993 1994 1995 1995 1996
---------------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Production:
Oil (MBbls)...................... 670 2,850 4,286 6,057 2,630 3,008
Gas (MMcf)....................... 1,484 3,704 7,234 12,393 5,619 7,016
MBOE............................. 917 3,467 5,492 8,123 3,567 4,178
Average Sales Prices(1):
Oil (per Bbl).................... $16.18 $13.82 $14.24 $17.39 $17.77 $19.80
Gas (per Mcf).................... 1.64 1.81 1.76 1.82 1.72 2.86
Per BOE.......................... 14.48 13.30 13.42 15.75 15.81 19.05
Average lease operating expenses
(per BOE)........................ $ 5.45 $ 4.10 $ 4.29 $ 3.70 $ 3.99 $ 3.95
</TABLE>
- ---------------
(1) Excludes results of hedging activities. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $14.23,
$14.56 and $17.27 in the years ended December 31, 1993, 1994 and 1995,
respectively, and the average gas price per Mcf received was $1.81 and
$1.84 in the years ended December 31, 1994 and 1995, respectively. The
Company did not enter into any hedging activities relating to oil during
1992 or relating to gas during 1992 and 1993. Hedging activities decreased
revenue recognized in the six months ended June 30, 1995 and 1996 by $1.0
million and $10.5 million, respectively. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $17.32 and
$17.92 and the average gas price per Mcf received was $1.75 and $2.17 in
the six months ended June 30, 1995 and 1996, respectively.
OIL AND GAS MARKETING AND MAJOR CUSTOMERS
The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and natural gas. The price received by
the Company for its oil and natural gas production
51
<PAGE> 52
depends on numerous factors beyond the Company's control, including seasonality,
the condition of the United States economy, particularly the manufacturing
sector, foreign imports, political conditions in other oil-producing and natural
gas-producing countries, the actions of the Organization of Petroleum Exporting
Countries and domestic government regulation, legislation and policies.
Decreases in the prices of oil and natural gas could have an adverse effect on
the carrying value of the Company's proved reserves and the Company's revenues,
profitability and cash flow. Although the Company is not currently experiencing
any significant involuntary curtailment of its oil or natural gas production,
market, economic and regulatory factors may in the future materially affect the
Company's ability to sell its oil or natural gas production. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
The Company has a long term contract to sell all crude oil volumes produced
from the Company's East Bay fields to Shell at a price based on the highest
monthly posted price of a number of principal purchasers of crude oil in the
South Louisiana area. The contract expires in June 2003. The Company markets its
remaining crude oil and natural gas production pursuant to short-term contracts.
For the year ended December 31, 1994, sales to ERAC accounted for
approximately 78% of the Company's oil and gas revenues. For the year ended
December 31, 1994, sales to Enron Oil Transportation and Trading accounted for
approximately 21.0% of the Company's oil and gas revenues. For the year ended
December 31, 1995, sales to Shell Oil Company, Murphy Oil USA, Inc. and Enron
Capital & Trade Resources Corp. accounted for 64%, 19% and 14%, respectively of
the Company's oil and gas revenues. For the six months ended June 30, 1996,
sales to Shell Oil Company, Murphy Oil USA, Inc. and Enron Capital & Trade
Resources Corp. accounted for 54%, 14% and 19%, respectively, of the Company's
oil and gas revenues.
Due to the availability of other markets and pipeline connections, the
Company does not believe that the loss of any single crude oil or natural gas
customer would adversely affect the Company's results of operations.
COMPETITION
The oil and gas industry is highly competitive in all of its phases. The
Company encounters competition from other oil and gas companies in all areas of
its operations, including the acquisition of producing properties. The Company's
competitors include major integrated oil and natural gas companies and numerous
independent oil and natural gas companies, individuals and drilling and income
programs. Many of its 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 than the Company. 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. The Company'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.
Capital available for investment in the oil and natural gas industry has
declined significantly as a result of decreases in product prices, changes in
federal income tax laws and adverse economic conditions generally affecting the
industry and the country as a whole. As a result, there is substantial
competition for such capital.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for and production and transportation of oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which can
result in loss of hydrocarbons, environmental pollution, personal injury claims,
and other damage to properties of the Company and others. Additionally, the
Company's oil and gas operations are located in an area that is subject to
tropical weather disturbances, some of which can be severe enough to cause
substantial damage to facilities and possibly interrupt production. As
protection against operating hazards, the Company maintains insurance coverage
against some, but not all, potential losses. The Company's coverages include,
but are not limited to, operator's extra expense, physical damage on certain
assets, employer's liability, comprehensive general liability, automobile,
workers' compensation and loss of production income insurance. The Company
believes
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that its insurance is adequate and customary for companies of a similar size
engaged in operations similar to those of the Company, but losses could occur
for uninsurable or uninsured risks or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered by insurance
could have an adverse impact on the Company's financial condition and results of
operations.
EMPLOYEES
As of August 1, 1996, the Company had 230 full-time employees, none of whom
is represented by any labor union. Included in the total were 96 corporate
employees located in the Company's Baton Rouge, Louisiana and Lafayette,
Louisiana offices, as well as 132 employees who work in the Company's East Bay
and Main Pass 69 fields. The Company considers its relations with its employees
to be good.
OTHER FACILITIES
The Company currently leases approximately 8,600 square feet of office
space in Baton Rouge, Louisiana, where its administrative offices are located,
and approximately 41,304 square feet of office space in Lafayette, Louisiana and
approximately 1,150 square feet of office space in New Orleans, Louisiana, where
the Company's technical personnel are collectively located.
The Company also leases dock and warehouse space in Venice, Louisiana.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and gas
industry. The Company's properties are subject to customary royalty interests,
liens incident to operating agreements, liens for current taxes and other
burdens which the Company believes do not materially interfere with the use of
or affect the value of such properties. The Company's Revolving Credit Facility
is secured by substantially all of the Company's oil and gas properties. The MMS
and Louisiana State Mineral Board must approve all transfers of record title or
operating rights on its respective leases. The MMS and Louisiana State Mineral
Board approval process can in some cases delay the requested transfer for a
significant period of time.
GOVERNMENTAL REGULATION
The Company's oil and gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by Federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Because such rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
laws.
The State of Louisiana and many other states require permits for drilling
operations, drilling bonds, and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells, and the regulation
of spacing, plugging, and abandonment of such wells.
The Federal Energy Regulatory Commission ("FERC") regulates the
transportation and certain sales for resale of natural gas in interstate
commerce pursuant to the Natural Gas Act of 1938 ("NGA") and the Natural Gas
Policy Act of 1978 ("NGPA"). In the past, the Federal government has regulated
the prices at which oil and gas could be sold. Deregulation of wellhead and
certain other sales in the natural gas industry began with the enactment of the
NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act
(the "Decontrol Act"). The Decontrol Act removed all NGA and NGPA price and
nonprice controls affecting wellhead sales of natural gas effective January 1,
1993. While sales by producers of natural gas, and all sales of crude oil,
condensate and natural gas liquids can currently be made at uncontrolled market
prices, Congress could reenact price controls in the future.
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On April 8, 1992, the FERC issued Order No. 636, as amended by Order No.
636-A (issued in August 1992) and Order No. 636-B (issued in November 1992) as a
continuation of its efforts to improve the competitive structure of the
interstate natural gas pipeline industry and maximize the consumer benefits of a
competitive wellhead gas market. The FERC proposed to generally require
interstate pipelines to "unbundle,"or separate, their traditional merchant sales
services from their transportation and storage services and to provide
comparable transportation and storage services with respect to all gas supplies
whether purchased from the pipeline or from other merchants such as marketers or
producers. The pipelines must now separately state the applicable rates for each
unbundled service (e.g., for natural gas transportation and for storage). This
unbundling process has been implemented through negotiated settlements in
individual pipeline restructuring proceedings. Ultimately, Order Nos. 636, et
al., may enhance the competitiveness of the natural gas market. It is impossible
to predict at this time the ultimate form and effect of Order No. 636. While
Order No. 636 will not directly regulate the production and sale of gas that may
be produced from the Company's properties, the order could affect the market
conditions in which the gas is sold and the availability of transportation
services to deliver the gas to market.
Certain segments of the industry have opposed aspects of Order Nos. 636, et
al., and several parties have sought court review of those orders. Furthermore,
after the FERC issued orders approving the individual pipeline restructuring
plans authorized pursuant to Order No. 636, various parties sought court review
of certain of these pipeline restructuring orders. Upon court review, any or all
of Order Nos. 636, et al., or the individual pipeline restructuring orders may
be reversed in whole or in part and remanded to the FERC for further action
consistent with the court's decision. It is impossible for the Company to
predict the ultimate outcome regarding this court review. In addition, the
composition of the FERC has changed considerably since the issuance of Order
Nos. 636, et al. The Company cannot, therefore, predict the ultimate outcome or
duration of the unbundled Order Nos. 636, et al regime.
The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order No. 636, and
the use of market-based rates for interstate gas transmission. While any
resulting FERC action would affect the company only indirectly, the FERC's
current rules and policy statements may have the effect of enhancing competition
in natural gas markets by, among other things, encouraging non-producer natural
gas marketers to engage in certain purchase and sale transactions. The Company
cannot predict what action the FERC will take on these matters, nor can it
accurately predict whether the FERC's actions will achieve the goal of
increasing the competition in markets in which the Company's natural gas is
sold. However, the Company does not believe that it will be treated materially
differently than other natural gas producers and marketers with which it
competes.
Recently, the FERC issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While this policy
statement affects the Company only indirectly, in its present form, the new
policy should enhance competition in natural gas markets and facilitate
construction of gas supply laterals. However, requests for rehearing of this
policy statement are currently pending. The Company cannot predict what action
the FERC will take on these requests.
Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will be
able automatically to change their transportation rates, subject to prescribed
ceiling levels. The indexing system, which allows or may require pipelines to
make rate changes to track changes in the Producer Price Index for Finished
Goods, minus one percent, became effective January 1, 1995. The FERC's decision
in this matter is currently the subject of various petitions for judicial
review. The Company is not able at this time to predict the effects of Order
Nos. 561 and 561-A, if any, on the transportation costs associated with oil
production from the Company's oil producing operations.
Under the Outer Continental Shelf Lands Act ("OCSLA"), the FERC also
regulates certain activities on the Outer Continental Shelf (the "OCS"). Under
OCSLA, all gathering and transporting of natural gas on the OCS must be
performed on an "open and non-discriminatory" basis. Consequently, the Company's
gathering and transportation facilities located on the OCS must be made
available to third parties. In addition,
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the MMS imposes regulations relating to development and production of oil and
gas properties in federal waters. Under certain circumstances, the MMS may
require any Company operations on federal leases to be suspended or terminated.
Any such suspensions or terminations could materially and adversely affect the
Company's financial condition and operations.
Certain of the Company's businesses are subject to regulation by the
Federal Natural Gas Pipeline Safety Act of 1968 and other state and Federal
environmental statutes and regulations.
The Oil Pollution Act of 1990 (the "OPA") imposes a variety of regulations
on "responsible parties" related to the prevention of oil spills and liability
for damages resulting from such spills in United States waters. A "responsible
party" includes the owner or operator of a facility or vessel, or the lessee or
permittee of an area in which an offshore facility is located. The OPA assigns
liability to each responsible party for oil removal costs and a variety of
public and private damages. While liability limits apply in some circumstances,
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 its cleanup, liability limits likewise do not
apply. Few defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party including
proof of financial responsibility to cover at least some costs in a potential
spill. On August 25, 1993, the MMS published an advance notice of its intention
to adopt regulations under the OPA that would require owners and operators of
offshore oil and natural gas facilities to establish $150 million in financial
responsibility. Under the proposed regulations, financial responsibility could
be established through insurance, guaranty, indemnity, surety bond, letter of
credit, qualification as a self-insurer or a combination thereof. There is
substantial uncertainty as to whether insurance companies or underwriters will
be willing to provide coverage under the OPA because the statute provides for
direct lawsuits against insurers who provide financial responsibility coverage,
and most insurers have strongly protested this requirement. The financial tests
or other criteria that will be used to judge self-insurance are also uncertain.
In November, 1995, the U.S. Senate approved a bill that would amend OPA 90 to
reduce the level of financial responsibility to $35 million, subject to
increases under certain circumstances. The U.S. House of Representatives passed
an amended version of the U.S. Senate bill on February 29, 1996. The measure is
now before a joint congressional conference. The Clinton Administration has
expressed its support for this legislation. The MMS had indicated that it would
not move forward with the adoption of its proposed rule until the United States
Congress has had an opportunity to act on the matter. Based on the passage of
these bills and the support of the Clinton administration, it appears that the
level of financial responsibility required under OPA 90 will be reduced. The
impact of the regulations should not be any more adverse to the Company than it
will be to other similarly situated or less capitalized owners or operators in
the Gulf of Mexico Region.
ENVIRONMENTAL MATTERS
The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to environmental
protection, including the generation, storage, handling, emission,
transportation and discharge of materials into the environment, and relating to
safety and health. The recent trend in environmental legislation and regulation
generally is toward stricter standards, and this trend will likely continue.
These laws and regulations may require the acquisition of a permit or other
authorization before construction or drilling commences and for certain other
activities; limit or prohibit construction, drilling and other activities on
certain lands lying within wilderness or wetlands and other protected areas; and
impose substantial liabilities for pollution resulting from the Company's
operations. The permits required for various of the Company's operations are
subject to revocation, modification and renewal by issuing authorities. The
Company believes that its operations currently are in substantial compliance
with applicable environmental regulations.
Governmental authorities have the power to enforce compliance with their
regulations, and violations are subject to fines or injunction, or both. The
Company does not expect environmental compliance matters to have a material
adverse effect on its financial position. It is also not anticipated that the
Company will be
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required in the near future to expend amounts that are material to the financial
condition or operations of the Company by reason of environmental laws and
regulations, but because such laws and regulations are frequently changed, and
may impose increasingly stricter requirements, the Company is unable to predict
the ultimate cost of complying with such laws and regulations.
The following are examples of environmental, safety and health laws that
potentially relate to the Company's operations:
Solid Waste. The Company's operations may generate and result in the
transportation, treatment, and disposal of both hazardous and nonhazardous solid
wastes that are subject to the requirements of the federal Resource Conservation
and Recovery Act and comparable state and local requirements. The Environmental
Protection Agency ("EPA") is currently considering the adoption of stricter
disposal standards for nonhazardous waste. Further, it is possible that some
wastes that are currently classified as nonhazardous, perhaps including wastes
generated during pipeline, drilling and production operations, may in the future
be designated as "hazardous wastes,"which are subject to more rigorous and
costly disposal requirements. Such changes in the regulations may result in
additional expenditures or operating expenses by the Company.
Hazardous Substances. The Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA") and comparable state statutes, also
known as "Superfund" laws, impose liability, without regard to fault or the
legality of the original conduct, on certain classes of persons for the release
of a "hazardous substance" into the environment. These persons include the owner
or operator of a site, and companies that transport, dispose of or arrange for
the disposal of, the hazardous substances found at the site. CERCLA also
authorizes the EPA, and in some cases, third parties to take actions in response
to threats to the public health or the environment and to seek to recover from
the classes of responsible persons the costs they incur. Although "petroleum" is
excluded from CERCLA's definition of a "hazardous substance," in the course of
its ordinary operations the Company may generate other materials which may fall
within the definition of a "hazardous substance." The Company may be responsible
under CERCLA for all or part of the costs required to clean up sites at which
such wastes have been disposed and for natural resource damages. The Company has
not received any notification that it may be potentially responsible for cleanup
costs under CERCLA or any comparable state law.
Air. The Company's operations may be subject to the Clean Air Act ("CAA")
and comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain pollution control requirements with respect to air emissions from the
operations of the Company. The EPA has been developing regulations to implement
these requirements. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, the Company does not
believe its operations will be materially adversely affected by any such
requirements.
Water. The Federal Water Pollution Control Act ("FWPCA") imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and gas wastes into navigable waters. Such discharges are typically
authorized by National Pollutant Discharge Elimination System ("NPDES") permits.
The FWPCA provides for civil, criminal and administrative penalties for any
unauthorized discharges of oil and other hazardous substances in reportable
quantities and, along with the Oil Pollution Act of 1990, imposes substantial
potential liability for the costs of removal, remediation and damages. State
laws for the control of water pollution also provide varying civil, criminal and
administrative penalties and liabilities in the case of a discharge of petroleum
or its derivatives into state waters. In addition, the Coastal Zone Management
Act authorizes state implementation and development of programs of management
measures for non-point source pollution to restore and protect coastal waters.
By January 1, 1997, unless authorized by an individual or general EPA permit,
for which the Company has applied with regard to its East Bay fields, the
federal NPDES permits prohibit the discharge of produced water, and some other
substances related to the oil and gas industry, from wells located in the
coastal waters of Louisiana. Although the costs to reformat Company operations,
if required, to comply with these zero discharge mandates under federal or state
law may be
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significant, the Company believes that these costs will not have a material
adverse impact on the Company's financial conditions and operations.
Protected Species. The Endangered Species Act ("ESA") seeks to ensure that
activities do not jeopardize endangered or threatened animal, fish and plant
species, nor destroy or modify the critical habitat of such species. Under the
ESA, exploration and production operations, as well as actions by federal
agencies, may not significantly impair or jeopardize the species or its habitat.
The ESA provides for criminal penalties for willful violations of the act. Other
statutes which provide protection to animal and plant species and which may
apply to the Company's operations which include, but are not necessarily limited
to, the Marine Mammal Protection Act, the Marine Protection and Sanctuaries Act,
the Fish and Wildlife Coordination Act, the Fishery Conservation and Management
Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.
Wetlands. Pursuant to the FWPCA, the United States Corps of Engineers,
with oversight by the EPA, administers a complex program that regulates
activities in wetland areas. Some of the Company's operations are in areas that
have been designated as wetlands and, as such, are subject to permitting
requirements. Failure to properly obtain a permit or violation of permit terms
could result in the issuance of compliance orders, restorative injunctions and a
host of civil, criminal and administrative penalties. The Company believes that
it is currently in substantial compliance with these permitting requirements.
Wildlife Refuges/Bird Sanctuaries. Portions of the Company's properties
are located in or adjacent to federal and state wildlife refuges and bird
sanctuaries. The Company's operations in such areas must comply with regulations
governing air and water discharge which are more stringent than its other areas
of operations. The Company has not been, and does not anticipate that it will
be, materially affected by any such requirements.
Safety and Health. The Company's operations are subject to the
requirements of the federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The OSHA hazard communication standard, the EPA
community-right-to-know regulations under Title III of the Federal Superfund
Amendment and Reauthorization Act, and similar state statutes require that
certain information be organized and maintained about hazardous materials used
or produced in the operations. Certain of this information must be provided to
employees, state and local government authorities and citizens.
The Company incurred approximately $430,000, $620,000, $694,000 and
$405,000 relating to environmental compliance during 1993, 1994, 1995 and the
six months ended June 30, 1996, respectively.
ABANDONMENT COSTS
The Company is responsible for payment of abandonment costs on the oil and
gas properties it operates. As of June 30, 1996, total abandonment costs on the
East Bay Complex and Main Pass 69 estimated to be incurred through the year 2008
were approximately $56 million. Estimates of abandonment costs and their timing
may change due to many factors including actual production results, inflation
rates, and changes in environmental laws and regulations.
In connection with its acquisition of the East Bay Complex and Main Pass
69, the Company entered into two escrow agreements to provide for the future
plugging and abandonment costs of these properties. The East Bay agreement
requires the Company to make monthly deposits of $100,000 through June 30, 1998,
and $350,000 thereafter until the balance in the escrow account equals $40
million unless the Company commits to the plug and abandonment of a certain
number of wells in which case the increase will be deferred. The Main Pass 69
agreement requires monthly deposits of $50,000 until the balance in the escrow
account equals $7.5 million. Such funds are restricted as to withdrawal by the
agreement. With respect to any specifically planned plugging and abandoning
operation, funds are partially released to the Company when it presents to the
escrow agent the planned plugging and abandonment operations approved by the
applicable governmental agency, with the balance to be released upon the
presentation by the Company to the trustee of evidence from the governmental
agency that the operation was conducted in compliance with applicable laws and
regulations. As of June 30, 1996, the escrow balances totaled $5.3 million.
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In addition, the MMS requires lessees of OCS properties to post 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 currently required to post area wide bonds of $3 million or $500,000
per producing lease and supplemental bonds at the discretion of the MMS. On
January 17, 1995, amended May 1, 1996, the Company entered into an agreement
with Planet Indemnity Company ("Planet") whereby Planet agreed to issue $11.7
million of MMS surety bonds for the Company and the Company agreed to post
collateral for same in favor of Planet. The collateral includes a mortgage on
the Company's federal (OCS) leases in the amount of $8.2 million, a letter of
credit for $2.0 million and a pledge of certain rights to escrowed funds. The
Company has posted a total of $14.2 million of bonds with the MMS and has
satisfied all requirements for bonds imposed to date by the MMS. Pursuant to a
schedule imposed by the MMS, the Company will be required to post additional
bonds up to a total bonding level of $24.6 million by January 1999, unless the
Company is determined by the MMS to be exempt from such requirement due to
certain financial tests. The Company does not anticipate that the cost of any
such bonding requirements will materially affect the Company's financial
position. Under certain circumstances, the MMS may require any Company
operations on federal leases to be suspended or terminated. Any such suspensions
or terminations could have a material adverse effect on the Company's financial
condition and operations.
LEGAL PROCEEDINGS
The Company is not a party to any material pending legal proceedings, other
than ordinary routine litigation incidental to its business that management
believes would not have a material adverse effect on its financial condition or
results of operations.
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MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information concerning the directors
and executive officers of the Company:
<TABLE>
<CAPTION>
NAME AGE POSITION
- --------------------------------------- --- --------------------------------------------
<S> <C> <C>
James C. Flores........................ 37 Chairman of the Board of Directors and
Chief Executive Officer
William W. Rucks, IV................... 39 Vice Chairman of the Board of Directors and
President
Richard G. Zepernick, Jr............... 35 Executive Vice President, Chief Operating
Officer and Director
Robert L. Belk......................... 47 Senior Vice President, Chief Financial
Officer Treasurer and Director
Donald W. Clayton...................... 60 Director
Milton J. Womack....................... 70 Director
Charles F. Mitchell.................... 47 Director
Robert K. Reeves....................... 38 Senior Vice President, General Counsel and
Secretary
David J. Morgan........................ 48 Senior Vice President -- Geology
Michael O. Aldridge.................... 37 Vice President -- Corporate Communications
William S. Flores, Jr.................. 39 Vice President -- Operations
Doss R. Bourgeois...................... 39 Vice President -- Production
Clint P. Credeur....................... 40 Vice President -- Reservoir Engineering
</TABLE>
The following biographies describe the business experience of the directors
and executive officers of the Company.
James C. Flores has served as Chairman of the Board of the Company since
its inception and as Chief Executive Officer since July 1995. From 1985 to 1992,
Mr. Flores served as Vice President of FloRuxco, Inc., an oil and gas
exploration company. From 1982 to 1984, Mr. Flores was an independent petroleum
landman.
William W. Rucks, IV has served as President and Vice Chairman of the Board
of Directors since July 1995 and served as President, Chief Executive Officer
and a Director of the Company from its inception until July 1995. From 1985 to
1992, Mr. Rucks served as President of FloRuxco, Inc. Prior thereto, Mr. Rucks
worked as a petroleum landman with Union Oil Company of California in its
Southwest Louisiana District, serving as Area Land Manager from 1981 to 1984.
Mr. Rucks will resign as President and Vice Chairman of the Board of Directors
upon consummation of the Common Stock Offering, but will continue to serve as a
member of the Board of Directors of the Company.
Richard G. Zepernick, Jr. has been with the Company since its inception,
presently serving as Executive Vice President and Chief Operating Officer. Mr.
Zepernick became a director of the Company in September 1994. From June 1992
until May 1993, Mr. Zepernick served as Senior Vice President and Secretary of
Flores & Rucks, Inc. From 1985 to 1992, Mr. Zepernick served as General Manager
of FloRuxco, Inc. Prior thereto, Mr. Zepernick worked as an independent
petroleum landman.
Robert L. Belk has served as Senior Vice President, Chief Financial Officer
and Treasurer of the Company since 1993. Mr. Belk became a director of the
Company in September 1994. Prior to joining the Company, Mr. Belk accumulated
over twelve years experience in public accounting working for Ernst & Young
(1981 to 1988) and H.J. Lowe & Company (1988 to 1993). Mr. Belk is a Certified
Public Accountant.
Donald W. Clayton has served as President and Director of Voyager Energy
Corp. since 1993. From 1992 to 1993 he served as President and Director of
Burlington Resources, Inc. and was the President and Chief Executive Officer of
Meridian Oil Company from 1987 to 1993. Mr. Clayton serves on the Louisiana
State
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University Petroleum Engineering Industry Advisory Board. Mr. Clayton become a
director of the Company in January 1995.
Milton J. Womack has owned and operated a general contracting firm in Baton
Rouge, Louisiana since 1955. Mr. Womack is Chairman of the Board of Union
Planters Bank of Louisiana, serves as a member of the Louisiana State University
Board of Supervisors and is a director of Union Planters Corporation. Mr. Womack
became a director of the Company in January 1995.
Charles F. Mitchell, M.D. is an otolaryngologist and plastic surgeon who
has operated a private practice in Baton Rouge, Louisiana since 1978. He is also
a Clinical Assistant Professor at the Louisiana State University Medical School
in New Orleans and Clinical Instructor at the University Medical Center in
Lafayette, Louisiana. Dr. Mitchell became a director of the Company in January
1995.
Robert K. Reeves has served as Senior Vice President, General Counsel and
Secretary of the Company since May 1994. From November 1993 to May 1994, Mr.
Reeves served as the Company's Vice President and General Counsel. Prior to
joining the Company in 1993, he was a partner in the law firm of Onebane,
Bernard, Torian, Diaz, McNamara & Abell in Lafayette, Louisiana, where he worked
for eleven years.
David J. Morgan joined the Company in 1993 as Vice President -- Geology and
became a Senior Vice President in December 1995. Mr. Morgan has 27 years of
experience in the oil and gas industry. From 1983 to 1993, Mr. Morgan served as
a geologist for and President of Morgan Resources, LTD., an oil and gas
exploration company. Mr. Morgan previously worked as a geologist for Sun Oil
Company, Baton Rouge Exploration Company and Campbell & Associates, an oil and
gas exploration and production company, from 1974 to 1977.
Michael O. Aldridge joined the Company in 1992 as Vice President and
Controller, and became Vice President -- Corporate Communications in September
1996. From 1991 until 1992, he was Vice President and Chief Financial Officer of
Fleet Petroleum Partners. From 1980 through 1991, Mr. Aldridge worked for Ernst
& Young where he attained the position of senior manager. Mr. Aldridge is a
Certified Public Accountant.
William S. Flores, Jr. joined the Company in 1993 as its Vice President --
Operations. Mr. Flores worked from 1988 to 1993 at CNG Producing Co. where he
served as a Senior Operations Engineer. From 1983 to 1988, he worked for Stokes
& Spiehler, Inc., an engineering consulting firm, and from 1981 to 1983, he
worked for Apache Corporation (formerly Dow Chemical Oil & Gas Division).
Doss R. Bourgeois has served as Vice President -- Production of the Company
since August 1993. From 1982 to 1993 Mr. Bourgeois worked for CNG Producing Co.
until he joined the Company. His positions at CNG Producing Co. included
Production Engineer, Manager Offshore Production, Supervisor Drilling
Engineering, and finally Workovers & Completion/Workover Superintendent. From
1979 to 1982, he was employed as a Drilling Engineer with Mobil Oil Company.
Clint P. Credeur has served the Company as Vice President -- Reservoir
Engineering since 1993. Mr. Credeur served as a Reservoir Engineer and Special
Projects Engineer with Chevron U.S.A. from November 1987 to December 1992. From
1981 to 1987 Mr. Credeur was a Projects Engineer with Tenneco and from 1978 to
1981 he was a Reservoir Engineer with Conoco.
James C. Flores and William S. Flores, Jr. are brothers; there are no other
family relationships between any of the directors and executive officers of the
Company.
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DESCRIPTION OF THE NOTES
The Notes will be issued under an indenture to be dated as of September 26,
1996 (the "Indenture") between the Company, as issuer, FRI Louisiana, as a
Subsidiary Guarantor, and Fleet National Bank, as trustee (the "Trustee"). A
copy of the Indenture in substantially the form in which it is to be executed
has been filed as an exhibit to the Registration Statement of which this
Prospectus is a part. The Indenture is subject to and governed by the Trust
Indenture Act of 1939, as amended (the "Trust Indenture Act"). The following
summary of the material provisions of the Indenture does not purport to be
complete and is subject to, and qualified in its entirety by reference to, all
of the provisions of the Indenture, including the definitions of certain terms
contained therein and those terms that are made a part of the Indenture by
reference to the Trust Indenture Act. The definitions of certain capitalized
terms used in the following summary are set forth below under "-- Certain
Definitions."
GENERAL
The Notes will be unsecured senior subordinated obligations of the Company
limited to $160,000,000 aggregate principal amount. The Notes will be issued
only in registered form, without coupons, in denominations of $1,000 and
integral multiples thereof. Principal of, premium, if any, on and interest on
the Notes will be payable, and the Notes will be transferable, at the office or
agency of the Company in the City of New York maintained for such purposes,
which initially will be the corporate trust office or agency of the Trustee
maintained at 777 Main Street, Hartford, CT 06115. In addition, interest may be
paid, at the option of the Company, by check mailed to the registered holders of
the Notes at their respective addresses as shown on the Note Register. No
service charge will be made for any transfer, exchange or redemption of Notes,
but the Company or the Trustee may require payment of a sum sufficient to cover
any tax or other governmental charge that may be payable in connection
therewith.
The obligations of the Company under the Notes will be guaranteed on an
unsecured senior subordinated basis by the Subsidiary Guarantor. See
"-- Subsidiary Guarantees of Notes."
MATURITY, INTEREST AND PRINCIPAL PAYMENTS
The Notes will mature on October 1, 2006. Interest on the Notes will accrue
at the rate of 9 3/4% per annum and will be payable semiannually on April 1 and
October 1 of each year, commencing April 1, 1997, to the Person in whose name
the Note is registered in the Note Register at the close of business on the
March 15 or September 15 next preceding such interest payment date. Interest
will be computed on the basis of a 360-day year comprised of twelve 30-day
months.
REDEMPTION
Optional Redemption. The Notes will be redeemable at the option of the
Company, in whole or in part, at any time on or after October 1, 2001, at the
redemption prices (expressed as percentages of principal amount) set forth
below, plus accrued and unpaid interest, if any, to the redemption date (subject
to the right of Holders of record on the relevant record date to receive
interest due on an interest payment date that is on or prior to the redemption
date), if redeemed during the 12-month period beginning on October 1 of the
years indicated below:
<TABLE>
<CAPTION>
YEAR PRICE
------------------------------------------------------------ --------
<S> <C>
2001........................................................ 104.875%
2002........................................................ 103.250%
2003........................................................ 101.625%
2004 and thereafter......................................... 100%
</TABLE>
Selection and Notice. In the event that less than all of the Notes are to
be redeemed at any time, selection of such Notes (or any portion thereof that is
an integral multiple of $1,000) for redemption will be made by the Trustee from
the outstanding Notes not previously called for redemption (or otherwise
purchased
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by the Company) on a pro rata basis, by lot or by such method as the Trustee
shall deem fair and appropriate; provided, however, that no Note with a
principal amount of $1,000 or less shall be redeemed in part. Notice of
redemption shall be mailed by first-class mail at least 30 but not more than 60
days before the redemption date to each holder of Notes to be redeemed at its
registered address. If any Note is to be redeemed in part only, the notice of
redemption that relates to such Note shall state the portion of the principal
amount thereof to be redeemed. A new Note in a principal amount equal to the
unredeemed portion thereof will be issued in the name of the Holder thereof upon
cancellation of the original Note. On and after the redemption date, interest
will cease to accrue on Notes or portions thereof called for redemption and
accepted for payment.
Offers to Purchase. As described below, (a) upon the occurrence of a
Change of Control, the Company is obligated to make an offer to purchase all
outstanding Notes at a purchase price equal to 101% of the principal amount
thereof, together with accrued and unpaid interest, if any, to the date of
purchase and (b) upon certain sales or other dispositions of assets, the Company
may be obligated to make offers to purchase Notes with a portion of the Net Cash
Proceeds of such sales or other dispositions at a purchase price equal to 100%
of the principal amount thereof, together with accrued and unpaid interest, if
any, to the date of purchase. See "-- Certain Covenants -- Change of Control"
and "-- Limitation on Disposition of Proceeds of Asset Sales."
SUBORDINATION
Payments of and distribution of or with respect to the Senior Subordinated
Note Obligations will be subordinated, to the extent set forth in the Indenture,
in right of payment to the prior payment in full in cash or cash equivalents of
all existing and future Senior Indebtedness, which includes, without limitation,
all Credit Agreement Obligations and Senior Note Obligations of the Company. The
Notes will rank prior in right of payment only to other indebtedness of the
Company which is, by its terms, expressly subordinated in right of payment to
the Notes. There is currently no indebtedness of the Company which would
constitute such subordinated indebtedness. In addition, the Senior Subordinated
Note Obligations will be effectively subordinated to all of the creditors of the
Company's subsidiaries, including trade creditors, except by virtue of a
Subsidiary Guarantee to the extent such Subsidiary is a Subsidiary Guarantor.
See "Risk Factors -- Subordination of Notes; Holding Company Structure."
The Indenture will provide that in the event of (a) any insolvency or
bankruptcy case or proceeding, or any receivership, liquidation, reorganization
or other similar case or proceeding in connection therewith, relating to the
Company (or its creditors, as such) or its assets, or (b) any liquidation,
dissolution or other winding-up of the Company, whether voluntary or
involuntary, or (c) any assignment for the benefit of creditors or other
marshaling of assets or liabilities of the Company, all Senior Indebtedness of
the Company must be paid in full in cash or cash equivalents before any direct
or indirect payment or distribution, whether in cash, property or securities
(excluding certain permitted equity and subordinated debt securities referred to
in the Indenture as "Permitted Junior Securities"), is made on account of the
Senior Subordinated Note Obligations. In the event that, notwithstanding the
foregoing, the Trustee or the holder of any Note receives any payment or
distribution of properties or assets of the Company of any kind or character,
whether in cash, property or securities, by set-off or otherwise, in respect of
Senior Subordinated Note Obligations before all Senior Indebtedness is paid or
provided for in full, then the Trustee or the holders of Notes receiving any
such payment or distribution (other than a payment or distribution in the form
of Permitted Junior Securities) will be required to pay or deliver such payment
or distribution forthwith to the trustee in bankruptcy, receiver, liquidating
trustee, custodian, assignee, agent or other person making payment or
distribution of assets of the Company for application to the payment of all
Senior Indebtedness remaining unpaid, to the extent necessary to pay all Senior
Indebtedness in full.
During the continuance of any default in the payment when due (whether at
Stated Maturity, upon scheduled repayment, upon acceleration or otherwise) of
principal of or premium, if any, or interest on, or of unreimbursed amounts
under drawn letters of credit or fees relating to letters of credit
constituting, any Designated Senior Indebtedness (a "Payment Default"), no
direct or indirect payment or distribution by or on behalf of the Company of any
kind or character shall be made on account of the Senior Subordinated Note
Obligations or any obligation under any Subsidiary Guarantee unless and until
such default has been cured or
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waived or has ceased to exist or such Designated Senior Indebtedness shall have
been discharged or paid in full in cash or cash equivalents.
In addition, during the continuance of any default other than a Payment
Default with respect to any Designated Senior Indebtedness pursuant to which the
maturity thereof may then be accelerated (a "Non-payment Default"), after
receipt by the Trustee from the holders (or their representative) of such
Designated Senior Indebtedness of a written notice of such Non-payment Default,
no payment or distribution of any kind or character may be made by the Company
on account of the Senior Subordinated Note Obligations for the period specified
below (the "Payment Blockage Period").
The Payment Blockage Period shall commence upon the receipt of notice of a
Non-payment Default by the Trustee from the holders (or their representative) of
Designated Senior Indebtedness stating that such notice is a payment blockage
notice pursuant to the Indenture and shall end on the earliest to occur of the
following events: (i) 179 days shall have elapsed since the receipt by the
Trustee of such notice; (ii) the date, as set forth in a written notice to the
Company or the Trustee from the holders (or their representative) of the
Designated Senior Indebtedness initiating such Payment Blockage Period, on which
such default is cured or waived or ceases to exist (provided that no other
Payment Default or Non-payment Default has occurred or is then continuing after
giving effect to such cure or waiver); (iii) the date on which such Designated
Senior Indebtedness is discharged or paid in full in cash or cash equivalents;
or (iv) the date, as set forth in a written notice to the Company or the Trustee
from the holders (or their representative) of the Designated Senior Indebtedness
initiating such Payment Blockage Period, on which such Payment Blockage Period
shall have been terminated by written notice to the Company or the Trustee from
the holders (or their representative) of Designated Senior Indebtedness
initiating such Payment Blockage Period, after which the Company, subject to the
subordination provisions set forth above and the existence of another Payment
Default, shall promptly resume making any and all required payments in respect
of the Notes, including any missed payments. Only one Payment Blockage Period
with respect to the Notes may be commenced within any 360 consecutive day
period. No Non-payment Default with respect to Designated Senior Indebtedness
that existed or was continuing on the date of the commencement of any Payment
Blockage Period with respect to the Designated Senior Indebtedness initiating
such Payment Blockage Period will be, or can be, made the basis for the
commencement of a second Payment Blockage Period, whether or not within a period
of 360 consecutive days, unless such default has been cured or waived for a
period of not less than 90 consecutive days (it being acknowledged that any
subsequent action, or any breach of any financial covenant for a period
commencing after the date of commencement of such Payment Blockage Period, that,
in either case, would give rise to a Non-payment Default pursuant to any
provision under which a Non-payment Default previously existed or was continuing
shall constitute a new Non-payment Default for this purpose; provided that, in
the case of a breach of a particular financial covenant, the Company shall have
been in compliance for at least one full 90 consecutive day period commencing
after the date of commencement of such Payment Blockage Period). In no event
will a Payment Blockage Period extend beyond 179 days from the date of the
receipt by the Trustee of the notice and there must be a 181 consecutive day
period in any 360-day period during which no Payment Blockage Period is in
effect. In the event that, notwithstanding the foregoing, the Company makes any
payment or distribution to the Trustee or the holder of any Note prohibited by
the subordination provision of the Indenture, then such payment or distribution
will be required to be paid over and delivered forthwith to the holders (or
their representative) of Designated Senior Indebtedness.
If the Company fails to make any payment on the Notes when due or within
any applicable grace period, whether or not on account of the payment blockage
provisions referred to above, such failure would constitute an Event of Default
under the Indenture and would enable the holders of the Notes to accelerate the
maturity thereof. See "-- Events of Default."
By reason of such subordination, in the event of liquidation, receivership,
reorganization or insolvency, creditors of the Company who are holders of Senior
Indebtedness may recover more, ratably, than the holders of the Notes, and funds
which would be otherwise payable to the holders of the Notes will be paid to the
holders of the Senior Indebtedness to the extent necessary to pay the Senior
Indebtedness in full, and the Company may be unable to meet its obligations in
full with respect to the Notes.
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As of June 30, 1996, on a pro forma basis, after giving effect pro forma to
the sale of the Notes and the estimated application of the net proceeds
therefrom, the aggregate amount of outstanding Senior Indebtedness would have
been approximately $125 million. See "Use of Proceeds," "Capitalization" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources." Although the Indenture will
contain limitations on the amount of additional Indebtedness that the Company
and the Restricted Subsidiaries may incur, the amounts of such Indebtedness
could be substantial and, in any case, such Indebtedness may be Senior
Indebtedness or Indebtedness of Subsidiaries (to which the Notes will be
structurally subordinated except for Indebtedness of a Subsidiary Guarantor).
The Indenture will prohibit the incurrence by the Company of Indebtedness which
is contractually subordinated in right of payment to any Senior Indebtedness of
the Company and senior in right of payment to the Notes. After giving effect to
the issuance of the Notes and the application of the net proceeds therefrom,
there will be no indebtedness of the Company which is subordinated in right of
payment to the Notes and there will be no indebtedness of the Company which is
pari passu in right of payment with the Notes.
SUBSIDIARY GUARANTEES OF NOTES
Initially, FRI Louisiana will be the only Subsidiary Guarantor, however,
other Restricted Subsidiaries may in the future incur Subsidiary Guarantees of
the Notes as described herein. Each Subsidiary Guarantor will guarantee, jointly
and severally, to each Holder and the Trustee, the full and prompt performance
of the Company's obligations under the Indenture and the Notes, including the
payment of principal of (premium, if any, on) and interest on the Notes pursuant
to its Subsidiary Guarantee. The Subsidiary Guarantees will be subordinated to
Guarantor Senior Indebtedness of a Subsidiary Guarantor to the same extent and
in the same manner as the Notes are subordinated to Senior Indebtedness. In
addition to the Subsidiary Guarantee, primarily for state income tax purposes,
FRI Louisiana will covenant with the Company to assume, as between the Company
and FRI Louisiana, the payment obligations under the Notes in exchange for the
advance of substantially all the net proceeds of the Notes Offering to FRI
Louisiana. Such intercompany assumption will not affect the primary liability of
the Company under the Notes.
The obligations of each subsidiary Guarantor are limited to the maximum
amount as will, after giving effect to all other contingent and fixed
liabilities (including, but not limited to, Guarantor Senior Indebtedness) of
such Subsidiary Guarantor and after giving effect to any collections from or
payments made by or on behalf of any other Subsidiary Guarantor in respect of
the obligations of such other Subsidiary Guarantor under its Subsidiary
Guarantee or pursuant to its contribution obligations under the Indenture,
result in the obligations of such Subsidiary Guarantor under the Subsidiary
Guarantee not constituting a fraudulent conveyance or fraudulent transfer under
federal or state law. Each Subsidiary Guarantor that makes a payment or
distribution under a Subsidiary Guarantee shall be entitled to a contribution
from each other Subsidiary Guarantor (if any) in a pro rata amount based on the
Adjusted Net Assets of each Subsidiary Guarantor.
Each Subsidiary Guarantor may consolidate with or merge into or sell all,
substantially all or any portion of its assets to the Company or another
Subsidiary Guarantor without limitation, except to the extent any such
transaction is subject to the "Merger, Consolidation and Sale of Assets"
covenant of the Indenture. Each Subsidiary Guarantor may consolidate with or
merge into or sell all of substantially all of its assets to a corporation other
than the Company or another Subsidiary Guarantor (whether or not affiliated with
the Subsidiary Guarantor), provided that (a) if the surviving corporation is not
the Subsidiary Guarantor, the surviving corporation agrees to assume such
Subsidiary Guarantor's Subsidiary Guarantee and all its obligations pursuant to
the Indenture (except to the extent the following paragraph would result in the
release of such Subsidiary Guarantee) and (b) such transaction does not (i)
violate any of the covenants described below under "Certain Covenants" or in the
Indenture or (ii) result in a Default or Event of Default immediately thereafter
that is continuing.
Upon the sale or other disposition (by merger or otherwise) of a Subsidiary
Guarantor (or all or substantially all of its Assets) to a Person other than the
Company or another Subsidiary Guarantor and pursuant to a transaction that is
otherwise in compliance with the Indenture (including as described in the
foregoing paragraph), such Subsidiary Guarantor shall be deemed released from
its Subsidiary Guarantee and
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the related obligations set forth in the Indenture; provided, however, that any
such termination shall occur only to the extent that all obligations of such
Subsidiary Guarantor under all of its guarantees of, and under all of its
pledges of assets or other security interests which secure other Indebtedness of
the Company or any Restricted Subsidiary shall also terminate or be released
upon such sale or other disposition. Each Subsidiary Guarantor that is
designated as an Unrestricted Subsidiary in accordance with the Indenture shall
be released from its Subsidiary Guarantee and related obligations set forth in
the Indenture for so long as it remains an Unrestricted Subsidiary.
Although the Indenture does not contain any requirement that any Subsidiary
(other than FRI Louisiana) execute and deliver a Subsidiary Guarantee, certain
covenants described below require a future Restricted Subsidiary to execute and
deliver a Subsidiary Guarantee prior to the guarantee of other Indebtedness. See
"Certain Covenants -- Limitation on Guarantees of Indebtedness by Restricted
Subsidiaries."
CERTAIN COVENANTS
The Indenture will contain, among others, the covenants described below.
Limitation on Indebtedness. (a) The Indenture will provide that neither
the Company nor any Restricted Subsidiary will create, incur, issue, assume,
guarantee or in any manner become directly or indirectly liable for the payment
of (collectively "incur") any Indebtedness (including any Acquired
Indebtedness), other than Permitted Indebtedness and Permitted Subsidiary
Indebtedness, as the case may be; provided, however, that the Company and its
Restricted Subsidiaries that are Subsidiary Guarantors may incur Indebtedness if
(x) the Company's Consolidated Fixed Charge Coverage Ratio for the four full
fiscal quarters immediately preceding the incurrence of such Indebtedness (and
for which financial statements are available), taken as one period (at the time
of such incurrence, after giving pro forma effect to: (i) the incurrence of such
Indebtedness and (if applicable) the application of the net proceeds therefrom,
including to refinance other Indebtedness, as if such Indebtedness was incurred
and the application of such proceeds occurred at the beginning of such
four-quarter period; (ii) the incurrence, repayment or retirement of any other
Indebtedness (including Permitted Indebtedness) by the Company or its Restricted
Subsidiaries since the first day of such four-quarter period (including any
other Indebtedness to be incurred concurrent with the incurrence of such
Indebtedness) as if such Indebtedness was incurred, repaid or retired at the
beginning of such four-quarter period; and (iii) notwithstanding clause (d) of
the definition of Consolidated Net Income, the acquisition (whether by purchase,
merger or otherwise) or disposition (whether by sale, merger or otherwise) of
any Person acquired or disposed of by the Company or its Restricted
Subsidiaries, as the case may be, since the first day of such four-quarter
period, as if such acquisition or disposition occurred at the beginning of such
four-quarter period), would have been equal to at least 2.5 to 1.0.
Limitation on Restricted Payments. (a) The Indenture will provide that the
Company will not, and will not permit any Restricted Subsidiary to, directly or
indirectly, take the following actions:
(i) declare or pay any dividend on, or make any distribution to
holders of, any shares of the Company's Capital Stock (other than dividends
or distributions payable solely in shares of Qualified Capital Stock of the
Company or in options, warrants or other rights to purchase Qualified
Capital Stock of the Company);
(ii) purchase, redeem or otherwise acquire or retire for value any
Capital Stock of the Company or any Affiliate thereof (other than any
Wholly Owned Restricted Subsidiary of the Company) or any options, warrants
or other rights to acquire such Capital Stock;
(iii) make any principal payment on or repurchase, redeem, defease or
otherwise acquire or retire for value, prior to any scheduled principal
payment, scheduled sinking fund payment or maturity, any Subordinated
Indebtedness;
(iv) declare or pay any dividend on, or make any distribution to the
holders of, any shares of Capital Stock of any Restricted Subsidiary of the
Company (other than to the Company or any of its Wholly Owned Restricted
Subsidiaries) or purchase, redeem or otherwise acquire or retire for value
any Capital
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Stock of any Restricted Subsidiary or any options, warrants or other rights
to acquire any such Capital Stock (other than with respect to any such
Capital Stock held by the Company or any Wholly Owned Restricted Subsidiary
of the Company);
(v) make any Investment (other than any Permitted Investment);
(vi) in connection with the acquisition of any property or asset by
the Company or its Restricted Subsidiaries after the date of the Indenture,
which property or asset would secure or be subject to any Production
Payment obligations of the Company or its Restricted Subsidiaries, make any
investment (of cash, property or other assets) in such property or asset so
acquired in addition to the amount of Indebtedness (including Production
Payment obligations) incurred by the Company or its Restricted Subsidiaries
in connection with such acquisition; or
(vii) incur, create, assume or suffer to exist any guarantee of
Indebtedness of any Affiliate (other than (a) guarantees of Indebtedness of
any Restricted Subsidiary by the Company or (b) guarantees of Indebtedness
of the Company by any Restricted Subsidiary, in each case in accordance
with the terms of the Indenture);
(such payments or other actions described in (but not excluded from) clauses (i)
through (vii) are collectively referred to as "Restricted Payments"), unless at
the time of and after giving effect to the proposed Restricted Payment (the
amount of any such Restricted Payment, if other than cash, shall be the amount
determined by the Board of Directors of the Company, whose determination shall
be conclusive and evidenced by a board resolution), (1) no Default or Event of
Default shall have occurred and be continuing, (2) the Company could incur $1.00
of additional Indebtedness (excluding Permitted Indebtedness) in accordance with
the "Limitation on Indebtedness" covenant, and (3) the aggregate amount of all
Restricted Payments declared or made after the date of the Indenture shall not
exceed the sum (without duplication) of the following:
(A) 50% of the aggregate cumulative Consolidated Net Income of the
Company accrued on a cumulative basis during the period beginning on the
first day of the month after which the Indenture is signed and ending on
the last day of the Company's last fiscal quarter ending prior to the date
of such proposed Restricted Payment (or, if such aggregate cumulative
Consolidated Net Income shall be a loss, minus 100% of such loss), plus
(B) the aggregate net cash proceeds received after the date of the
Indenture by the Company as capital contributions to the Company (other
than from any Restricted Subsidiary), plus
(C) the aggregate net cash proceeds received after the date of the
Indenture by the Company from the issuance or sale (other than to any of
its Restricted Subsidiaries) of shares of Qualified Capital Stock of the
Company or any options, warrants or rights to purchase such shares of
Qualified Capital Stock of the Company, plus
(D) the aggregate net cash proceeds received after the date of the
Indenture by the Company (other than from any of its Restricted
Subsidiaries) upon the exercise of any options, warrants or rights to
purchase shares of Qualified Capital Stock of the Company, plus
(E) the aggregate net cash proceeds received after the date of the
Indenture by the Company from the issuance or sale (other than to any of
its Restricted Subsidiaries) of debt securities or shares of Redeemable
Capital Stock that have been converted into or exchanged for Qualified
Capital Stock of the Company to the extent such debt securities were
originally sold for cash, together with the aggregate cash received by the
Company at the time of such conversion or exchange, plus
(F) To the extent not otherwise included in the Company's Consolidated
Net Income, the net reduction in Investments in Unrestricted Subsidiaries
resulting from the payments of interest on Indebtedness, dividends,
repayments of loans or advances, or other transfers of assets, in each case
to the Company or a Restricted Subsidiary after the date of the Indenture
from any Unrestricted Subsidiary or from the redesignation of an
Unrestricted Subsidiary as a Restricted Subsidiary (valued in each case as
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provided in the definition of Investment), not to exceed in the case of any
Unrestricted Subsidiary the total amount of Investments (other than
Permitted Investments) in such Unrestricted Subsidiary made by the Company
and its Restricted Subsidiaries in such Unrestricted Subsidiary after the
date of the Indenture, plus
(G) $15,000,000.
(b) Notwithstanding paragraph (a) above, the Company and its Restricted
Subsidiaries may take the following actions so long as (in the case of clauses
(ii), (iii) and (iv) below) no Default or Event of Default shall have occurred
and be continuing:
(i) the payment of any dividend within 60 days after the date of
declaration thereof, if at such declaration date such declaration complied
with the provisions of paragraph (a) above (and such payment shall be
deemed to have been paid on such date of declaration for purposes of any
calculation required by the provisions of paragraph (a) above);
(ii) the repurchase, redemption or other acquisition or retirement of
any shares of any class of Capital Stock of the Company or any Restricted
Subsidiary, in exchange for, or out of the aggregate net cash proceeds of,
a substantially concurrent issue and sale (other than to a Restricted
Subsidiary) of shares of Qualified Capital Stock of the Company;
(iii) the purchase, redemption, repayment, defeasance or other
acquisition or retirement for value of any Subordinated Indebtedness (other
than Redeemable Capital Stock) in exchange for or out of the aggregate net
cash proceeds of a substantially concurrent issue and sale (other than to a
Restricted Subsidiary) of shares of Qualified Capital Stock of the Company;
and
(iv) the purchase, redemption, repayment, defeasance or other
acquisition or retirement for value of Subordinated Indebtedness (other
than Redeemable Capital Stock) in exchange for, or out of the aggregate net
cash proceeds of a substantially concurrent incurrence (other than to a
Restricted Subsidiary) of, Subordinated Indebtedness of the Company so long
as (A) the principal amount of such new Indebtedness does not exceed the
principal amount (or, if such Subordinated Indebtedness being refinanced
provides for an amount less than the principal amount thereof to be due and
payable upon a declaration of acceleration thereof, such lesser amount as
of the date of determination) of the Subordinated Indebtedness being so
purchased, redeemed, repaid, defeased, acquired or retired, plus the amount
of any premium required to be paid in connection with such refinancing
pursuant to the terms of the Subordinated Indebtedness refinanced or the
amount of any premium reasonably determined by the Company as necessary to
accomplish such refinancing, plus the amount of expenses of the Company
incurred in connection with such refinancing, (B) such new Subordinated
Indebtedness is subordinated to the Notes at least to the same extent as
such Subordinated Indebtedness so purchased, redeemed, repaid, defeased,
acquired or retired, (C) such new Subordinated Indebtedness has an Average
Life to Stated Maturity that is longer than the Average Life to Stated
Maturity of the Notes and such new Subordinated Indebtedness has a Stated
Maturity for its final scheduled principal payment that is at least 91 days
later than the Stated Maturity for the final scheduled principal payment of
the Notes.
The actions described in clauses (i), (ii) and (iii) of this paragraph (b) shall
be Restricted Payments that shall be permitted to be taken in accordance with
this paragraph (b) but shall reduce the amount that would otherwise be available
for Restricted Payments under clause (3) of paragraph (a) (provided that any
dividend paid pursuant to clause (i) of this paragraph (b) shall reduce the
amount that would otherwise be available under clause (3) of paragraph (a) when
declared, but not also when subsequently paid pursuant to such clause (i)), and
the actions described in clause (iv) of this paragraph (b) shall be Restricted
Payments that shall be permitted to be taken in accordance with this paragraph
and shall not reduce the amount that would otherwise be available for Restricted
Payments under clause (3) of paragraph (a).
(c) In computing Consolidated Net Income of the Company under paragraph (a)
above, (1) the Company shall use audited financial statements for the portions
of the relevant period for which audited financial statements are available on
the date of determination and unaudited financial statements and other
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current financial data based on the books and records of the Company for the
remaining portion of such period and (2) the Company shall be permitted to rely
in good faith on the financial statements and other financial data derived from
the books and records of the Company that are available on the date of
determination. If the Company makes a Restricted Payment which, at the time of
the making of such Restricted Payment would in the good faith determination of
the Company be permitted under the requirements of the Indenture, such
Restricted Payment shall be deemed to have been made in compliance with the
Indenture notwithstanding any subsequent adjustments made in good faith to the
Company's financial statements affecting Consolidated Net Income of the Company
for any period.
Limitation on Issuances and Sales of Restricted Subsidiary Stock. The
Indenture will provide that the Company (i) will not permit any Restricted
Subsidiary to issue any Preferred Stock (other than to the Company or a Wholly
Owned Restricted Subsidiary) and (ii) will not permit any Person (other than the
Company and/or one or more Wholly Owned Restricted Subsidiaries) to own any
Capital Stock of any Restricted Subsidiary; provided, however, that this
covenant shall not prohibit (1) the issuance and sale of all, but not less than
all, of the issued and outstanding Capital Stock of any Restricted Subsidiary
owned by the Company or any of its Restricted Subsidiaries in compliance with
the other provisions of the Indenture, or (2) the ownership by directors of
directors' qualifying shares or the ownership by foreign nationals of Capital
Stock of any Restricted Subsidiary, to the extent mandated by applicable law.
Limitation on Transactions with Affiliates. The Indenture will provide
that the Company will not, and will not permit any Restricted Subsidiary to,
directly or indirectly, enter into or suffer to exist any transaction or series
of related transactions (including, without limitation, the sale, purchase,
exchange or lease of assets, property or the rendering of any services) with, or
for the benefit of, any Affiliate of the Company (each, other than a Restricted
Subsidiary, being an "Interested Person"), unless (i) such transaction or series
of transactions are on terms that are no less favorable to the Company or such
Restricted Subsidiary, as the case may be, than those that would be available in
a comparable arm's length transaction with unrelated third parties who are not
Interested Persons, (ii) with respect to any one transaction or series of
transactions involving aggregate payments in excess of $1,000,000, the Company
delivers an officer's certificate to the Trustee certifying that such
transaction or series of transactions complies with clause (i) above and such
transaction or series of transactions have been approved by the Board of
Directors of the Company, and (iii) with respect to any one transaction or
series of transactions involving aggregate payments in excess of $10,000,000,
the officer's certificate referred to in clause (ii) above also certifies that
such transaction or series of transactions have been approved by a majority of
the Disinterested Directors (or, in the event there are no such Disinterested
Directors, that the Company has obtained a written opinion from an independent
nationally recognized investment banking firm or appraisal firm, in either case
specializing or having a specialty in the type and subject matter of the
transaction or series of transactions at issue, which opinions shall be to the
effect set forth in clause (i) above or shall state that such transaction or
series of transactions are fair from a financial point of view to the Company or
such Restricted Subsidiary); provided, however, that this covenant will not
restrict the Company from (1) paying reasonable and customary regular
compensation and fees to directors of the Company who are not employees of the
Company or any Restricted Subsidiary or (2) paying dividends on, or making
distributions with respect to, shares of Capital Stock of the Company on a pro
rata basis to the extent permitted by the "Limitation on Restricted Payments"
covenant.
Limitation on Liens. The Indenture will provide that the Company will not,
and will not permit any Restricted Subsidiary to, directly or indirectly,
create, incur, assume, affirm or suffer to exist or become effective any Lien of
any kind, except for Permitted Liens, on or with respect to any of its property
or assets (including any intercompany notes), whether owned at the date of the
Indenture or thereafter acquired, or any income, profits or proceeds therefrom,
or assign or otherwise convey any right to receive income thereon, unless (x) in
the case of any Lien securing Subordinated Indebtedness, the Notes are secured
by a Lien on such property, assets or proceeds that is senior in priority to
such Lien and (y) in the case of any other Lien, the Notes are directly secured
equally and ratably with the obligation or liability secured by such Lien. The
incurrence of additional secured Indebtedness by the Company or any Restricted
Subsidiary is subject to further limitations on the incurrence of Indebtedness
as described under "-- Limitation on Indebtedness."
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Change of Control. Upon the occurrence of a Change of Control, the Company
shall be obligated to make an offer to purchase all of the then outstanding
Notes (a "Change of Control Offer"), and shall purchase, on a business day (the
"Change of Control Purchase Date") not more than 70 nor less than 30 days
following the Change of Control, all of the then outstanding Notes validly
tendered pursuant to such Change in Control Offer, at a purchase price (the
"Change of Control Purchase Price") equal to 101% of the principal amount
thereof plus accrued and unpaid interest, if any, to the Change of Control
Purchase Date. The Change of Control Offer is required to remain open for at
least 20 Business Days and until the close of business on the Change of Control
Purchase Date.
In order to effect such Change of Control Offer, the Company shall, not
later than the 30th day after the Change of Control, mail to each Noteholder a
notice of the Change of Control Offer, which notice shall govern the terms of
the Change of Control Offer and shall state, among other things, the procedures
that Noteholders must follow to accept the Change of Control Offer.
If a Change of Control Offer is made, there can be no assurance that the
Company will have available funds sufficient to pay the Change of Control
Purchase Price for all of the Notes that might be delivered by Noteholders
seeking to accept the Change of Control Offer. If on a Change of Control
Purchase Date the Company does not have available funds sufficient to pay the
Change of Control Purchase Price or is prohibited from purchasing the Notes, an
Event of Default would occur under the Indenture. The definition of Change of
Control includes an event by which the Company sells, conveys, transfers or
leases all or substantially all of its properties to any Person; the phrase "all
or substantially all" is subject to applicable legal precedent and as a result
in the future there may be uncertainty as to whether a Change of Control has
occurred.
The Company will not be required to make a Change of Control Offer upon a
Change of Control if a third party makes the Change of Control Offer at the same
purchase price, at the same times and otherwise in substantial compliance with
the requirements applicable to a Change of Control Offer made by the Company and
purchases all Notes validly tendered and not withdrawn under such Change of
Control Offer.
The Company intends to comply with Rule 14e-1 under the Exchange Act and
any other securities laws and regulations thereunder, if applicable, in the
event that a Change of Control occurs and the Company is required to purchase
Notes as described above. The existence of a Holder's right to require, subject
to certain conditions, the Company to repurchase its Notes upon a Change of
Control may deter a third party from acquiring the Company in a transaction that
constitutes, or results in, a Change of Control.
Limitation on Disposition of Proceeds of Asset Sales. (a) The Indenture
will provide that the Company will not, and will not permit any Restricted
Subsidiary to, engage in any Asset Sale unless (i) the Company or such
Restricted Subsidiary, as the case may be, receives consideration at the time of
such Asset Sale at least equal to the fair market value of the assets and
properties sold or otherwise disposed of pursuant to the Asset Sale (as
determined by the Board of Directors of the Company, whose determination shall
be conclusive and evidenced by a board resolution) and (ii) at least 75% of the
consideration received by the Company or the Restricted Subsidiary, as the case
may be, in respect of such Asset Sale consists of cash, Cash Equivalents or the
assumption by the purchaser of liabilities of the Company (other than
liabilities of the Company that are by their terms subordinated to the Notes) or
any Restricted Subsidiary as a result of which the Company and its remaining
Restricted Subsidiaries are no longer liable.
(b) If the Company or any Restricted Subsidiary engages in an Asset Sale,
the Company may either (x) apply the Net Cash Proceeds thereof to permanently
reduce Senior Indebtedness or to permanently reduce Guarantor Senior
Indebtedness, or (y) invest all or any part of the Net Cash Proceeds thereof,
within 365 days after such Asset Sale, in properties and assets which replace
the properties and assets that were the subject of the Asset Sale or in
properties and assets that will be used in the business of the Company or its
Restricted Subsidiaries, as the case may be ("Replacement Assets"). The amount
of such Net Cash Proceeds not applied or invested as provided in this paragraph
constitutes "Excess Proceeds."
(c) When the aggregate amount of Excess Proceeds equals or exceeds
$15,000,000, the Company shall make an offer to purchase, from all Holders of
the Notes and any then outstanding Pari Passu Indebtedness required to be
repurchased or repaid on a permanent basis in connection with an Asset Sale, an
aggregate
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principal amount of Notes and any then outstanding Pari Passu Indebtedness equal
to such Excess Proceeds as follows:
(i) (A) the Company shall make an offer to purchase (a "Net Proceeds
Offer") from all Holders of the Notes in accordance with the procedures set
forth in the Indenture the maximum principal amount (expressed as a
multiple of $1,000) of Notes that may be purchased out of an amount (the
"Payment Amount") equal to the product of such Excess Proceeds multiplied
by a fraction, the numerator of which is the outstanding principal amount
of the Notes and the denominator of which is the sum of the outstanding
principal amount of the Notes and such Pari Passu Indebtedness, if any
(subject to proration in the event such amount is less than the aggregate
Offered Price (as defined herein) of all Notes tendered), and (B) to the
extent required by such Pari Passu Indebtedness and provided there is a
permanent reduction in the principal amount of such Pari Passu
Indebtedness, the Company shall make an offer to purchase Pari Passu
Indebtedness (a "Pari Passu Offer") in an amount (the "Pari Passu
Indebtedness Amount") equal to the excess of the Excess Proceeds over the
Payment Amount.
(ii) The offer price for the Notes shall be payable in cash in an
amount equal to 100% of the principal amount of the Notes tendered pursuant
to a Net Proceeds Offer, plus accrued and unpaid interest, if any, to the
date such Net Proceeds Offer is consummated (the "Offered Price"), in
accordance with the procedures set forth in the Indenture. To the extent
that the aggregate Offered Price of the Notes tendered pursuant to a Net
Proceeds Offer is less than the Payment Amount relating thereto or the
aggregate amount of the Pari Passu Indebtedness that is purchased or repaid
pursuant to the Pari Passu Offer is less than the Pari Passu Indebtedness
Amount (such shortfall constituting a "Net Proceeds Deficiency"), the
Company may use such Net Proceeds Deficiency, or a portion thereof, for
general corporate purposes, subject to the limitations of the "Limitation
on Restricted Payments" covenant.
(iii) If the aggregate Offered Price of Notes validly tendered and not
withdrawn by Holders thereof exceeds the Payment Amount, Notes to be
purchased will be selected on a pro rata basis. Upon completion of such Net
Proceeds Offer and Pari Passu Offer, the amount of Excess Proceeds shall be
reset to zero.
The Company will not permit any Subsidiary to enter into or suffer to exist any
agreement that would place any restriction of any kind (other than pursuant to
law or regulation) on the ability of the Company to make a Net Proceeds Offer
following any Asset Sale. The Company intends to comply with Rule 14e-1 under
the Exchange Act, and any other securities laws and regulations thereunder, if
applicable, in the event that an Asset Sale occurs and the Company is required
to purchase Notes as described above.
Limitation on Guarantees of Indebtedness by Restricted Subsidiaries. (a)
The Indenture will provide that the Company will not permit any Restricted
Subsidiary that is not a Subsidiary Guarantor to guarantee the payment of any
Indebtedness of the Company unless (i)(A) such Restricted Subsidiary
simultaneously executes and delivers a supplemental indenture to the Indenture
providing for an Subsidiary Guarantee of the Notes by such Restricted Subsidiary
which Subsidiary Guarantee will be subordinated to Guarantor Senior Indebtedness
(but no other Indebtedness) to the same extent that the Notes are subordinated
to Senior Indebtedness and (B) with respect to any guarantee of Subordinated
Indebtedness by a Restricted Subsidiary, any such guarantee shall be
subordinated to such Restricted Subsidiary's Subsidiary Guarantee at least to
the same extent as such Subordinated Indebtedness is subordinated to the Notes;
(ii) such Restricted Subsidiary waives and will not in any manner whatsoever
claim or take the benefit or advantage of, any rights of reimbursement,
indemnity or subrogation or any other rights against the Company or any other
Restricted Subsidiary as a result of any payment by such Restricted Subsidiary
under its Subsidiary Guarantee until such time as the obligations guaranteed
thereby are paid in full; and (iii) such Restricted Subsidiary shall deliver to
the Trustee an Opinion of Counsel to the effect that such Subsidiary Guarantee
has been duly executed and authorized and constitutes a valid, binding and
enforceable obligation of such Restricted Subsidiary, except insofar as
enforcement thereof may be limited by bankruptcy, insolvency or similar laws
(including, without limitation, all laws relating to fraudulent transfers) and
except insofar as enforcement thereof is subject to general principles of
equity; provided that this paragraph (a) shall not be applicable to any
guarantee of any
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Restricted Subsidiary that (x) existed at the time such Person became a
Restricted Subsidiary of the Company and (y) was not incurred in connection
with, or in contemplation of, such Person becoming a Restricted Subsidiary of
the Company.
(b) Notwithstanding the foregoing and the other provisions of the
Indenture, any Subsidiary Guarantee incurred by a Restricted Subsidiary pursuant
to this covenant shall provide by its terms that it shall be automatically and
unconditionally released and discharged upon (i) any sale, exchange or transfer,
to any Person that is not an Affiliate of the Company, of all of the Company's
Capital Stock in, or all or substantially all the assets of, such Restricted
Subsidiary (which sale, exchange or transfer is not prohibited by the
Indenture), (ii) the merger of such Restricted Subsidiary into the Company or
any other Restricted Subsidiary (provided the surviving Restricted Subsidiary
assumes the Subsidiary Guarantee) or the liquidation and dissolution of such
Restricted Subsidiary (in each case to the extent not prohibited by the
Indenture), or (iii) the release or discharge of the guarantee which resulted in
the creation of such Subsidiary Guarantee of the Notes, except a discharge or
release by or as a result of payment under such guarantee.
Limitation on Dividends and Other Payment Restrictions Affecting Restricted
Subsidiaries. The Indenture will provide that the Company will not, and will
not permit any Restricted Subsidiary to, directly or indirectly, create or
otherwise cause or suffer to exist or become effective any consensual
encumbrance or restriction of any kind on the ability of any Restricted
Subsidiary to (a) pay dividends, in cash or otherwise, or make any other
distributions on or in respect of its Capital Stock to the Company or any other
Restricted Subsidiary, (b) pay any Indebtedness owed to the Company or any other
Restricted Subsidiary, (c) make an Investment in the Company or any other
Restricted Subsidiary or (d) transfer any of its properties or assets to the
Company or any other Restricted Subsidiary, except for such encumbrances or
restrictions (i) pursuant to an agreement in effect or entered into on the date
of the Indenture, (ii) any agreement or other instrument of a Person acquired by
the Company or any Restricted Subsidiary in existence at the time of such
acquisition (but not created in contemplation thereof), which encumbrance or
restriction is not applicable to any other Person, or the properties or assets
of any other Person, other than the Person, or the property or assets of the
Person, so acquired or (iii) existing under any agreement that extends, renews,
refinances or places the agreements containing the restrictions in the foregoing
clauses (i) and (ii), provided that the terms and conditions of any such
restrictions are not materially less favorable to the Holders of the Notes than
those under or pursuant to the agreement evidencing the Indebtedness so
extended, renewed, refinanced or replaced.
Limitation on Other Senior Subordinated Indebtedness. The Indenture will
provide that the Company will not incur, directly or indirectly, any
Indebtedness which is expressly subordinate or junior in right of payment in any
respect to Senior Indebtedness unless such Indebtedness ranks pari passu in
right of payment with the Notes, or is expressly subordinated in right of
payment to the Notes.
Reports. The Indenture will require that the Company (and the Subsidiary
Guarantors, if applicable) file on a timely basis with the Commission, to the
extent such filings are accepted by the Commission and whether or not the
Company has a class of securities registered under the Exchange Act, the annual
reports, quarterly reports and other documents that the Company would be
required to file if it were subject to Section 13 or 15 of the Exchange Act. The
Company (and the Subsidiary Guarantors, if applicable) will also be required (a)
to file with the Trustee, and provide to each holder of Notes, without cost to
such holder, copies of such reports and documents within 15 days after the date
on which the Company files such reports and documents with the Commission or the
date on which the Company (and the Subsidiary Guarantors, if applicable) would
be required to file such reports and documents if the Company (and the
Subsidiary Guarantors, if applicable) were so required and (b) if filing such
reports and documents with the Commission is not accepted by the Commission or
is prohibited under the Exchange Act, to supply at the Company's cost copies of
such reports and documents to any holder of Notes promptly upon written request.
Future Designation of Restricted and Unrestricted Subsidiaries. The
foregoing covenants (including calculation of financial ratios and the
determination of limitations on the incurrence of Indebtedness and Liens) may be
affected by the designation by the Company of any existing or future Subsidiary
of the Company as an Unrestricted Subsidiary. Generally, a Restricted Subsidiary
includes any Subsidiary of the Company, whether existing on or after the date of
the Indenture, unless the Subsidiary of the Company is
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designated as an Unrestricted Subsidiary pursuant to the terms of the Indenture.
The definition of "Unrestricted Subsidiary" set forth under the caption
"-- Certain Definitions" describes the circumstances under which a future
Subsidiary of the Company may be designated as an Unrestricted Subsidiary by the
Board of Directors of the Company.
MERGER, CONSOLIDATION AND SALE OF ASSETS, ETC.
The Company will not, in any single transaction or series of related
transactions, merge or consolidate with or into any other Person, or sell,
assign, convey, transfer, lease or otherwise dispose of all or substantially all
of its properties and assets to any Person or group of Affiliated Persons, and
the Company will not permit any of its Restricted Subsidiaries to enter into any
such transaction or series of transactions if such transaction or series of
transactions, in the aggregate, would result in a sale, assignment, conveyance,
transfer, lease or other disposition of all or substantially all of the
properties and assets of the Company and its Restricted Subsidiaries on a
consolidated basis to any other Person or group of Affiliated Persons, unless at
the time and after giving effect thereto (i) either (A) if the transaction or
transactions is a merger or consolidation, the Company shall be the surviving
Person of such merger or consolidation, or (B) the Person (if other than the
Company) formed by such consolidation or into which the Company or such
Restricted Subsidiary is merged or to which the properties and assets of the
Company or such Restricted Subsidiary, as the case may be, are sold, assigned,
conveyed, transferred, leased or otherwise disposed of (any such surviving
Person or transferee Person being the "Surviving Entity") shall be a corporation
organized and existing under the laws of the United States of America, any state
thereof or the District of Columbia and shall, in either case, expressly assume
by a supplemental indenture to the Indenture executed and delivered to the
Trustee, in form satisfactory to the Trustee, all the obligations of the Company
under the Notes and the Indenture, and, in each case, the Indenture shall remain
in full force and effect; (ii) immediately before and immediately after giving
effect to such transaction or series of transactions on a pro forma basis (and
treating any Indebtedness not previously an obligation of Company or any of its
Restricted Subsidiaries in connection with or as a result of such transaction as
having been incurred at the time of such transaction), no Default or Event of
Default shall have occurred and be continuing; (iii) except in the case of the
consolidation or merger of any Restricted Subsidiary with or into the Company,
immediately after giving effect to such transaction or transactions on a pro
forma basis, the Consolidated Net Worth of the Company (or the Surviving Entity
if the Company is not the continuing obligor under the Indenture) is at least
equal to the Consolidated Net Worth of the Company immediately before such
transaction or transactions; (iv) except in the case of the consolidation or
merger of any Restricted Subsidiary with or into the Company or any Wholly Owned
Restricted Subsidiary, immediately before and immediately after giving effect to
such transaction or transactions on a pro forma basis (on the assumption that
the transaction or transactions occurred on the first day of the period of four
fiscal quarters ending immediately prior to the consummation of such transaction
or transactions, with the appropriate adjustments with respect to the
transaction or transactions being included in such pro forma calculation), the
Company (or the Surviving Entity if the Company is not the continuing obligor
under the Indenture) could incur $1.00 of additional Indebtedness (excluding
Permitted Indebtedness) pursuant to the "Limitation on Indebtedness" covenant;
(v) each Subsidiary Guarantor, unless it is the other party to the transactions
described above, shall have by supplemental indenture to the Indenture confirmed
that its Subsidiary Guarantee of the Notes shall apply to such Person's
obligations under the Indenture and the Notes; and (vi) if any of the properties
or assets of the Company or any of its Restricted Subsidiaries would upon such
transaction or series of related transactions become subject to any Lien (other
than a Permitted Lien), the creation and imposition of such Lien shall have been
in compliance with the "Limitation on Liens" covenant.
In connection with any consolidation, merger, transfer, lease or other
disposition contemplated hereby, the Company shall deliver, or cause to be
delivered, to the Trustee, in form and substance reasonably satisfactory to the
Trustee, an Officers' Certificate stating that such consolidation, merger,
transfer, lease or other disposition and the supplemental indenture in respect
thereto comply with the requirements under the Indenture and an Opinion of
Counsel stating that the requirements of clause (i) of the preceding paragraph
have been complied with.
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Upon any consolidation or merger or any sale, assignment, transfer, lease
or other disposition of all or substantially all of the assets of the Company in
accordance with the foregoing, in which the Company is not the continuing
corporation, the Surviving Entity shall succeed to, and be substituted for, and
may exercise every right and power of, the Company under the Indenture with the
same effect as if such successor corporation had been named as the Company
therein, and thereafter the Company, except in the case of a lease. will be
discharged from all obligations and covenants under the Indenture and the Notes.
EVENTS OF DEFAULT
The following will be "Events of Default" under the Indenture:
(i) default in the payment of the principal of or premium, if any, on
any of the Notes, whether such payment is due at maturity, upon redemption,
upon repurchase pursuant to a Change of Control Offer or a Net Proceeds
Offer, upon acceleration or otherwise; or
(ii) default in the payment of any installment of interest on any of
the Notes, when it becomes due and payable, and the continuance of such
default for a period of 30 days; or
(iii) default in the performance or breach of the provisions of the
"Merger, Consolidation and Sale of Assets" section of the Indenture, the
failure to make or consummate a Change in Control Offer in accordance with
the provisions of the "Change in Control" covenant or the failure to make
or consummate a Net Proceeds Offer in accordance with the provisions of the
"Limitation on Disposition of Proceeds of Asset Sales" covenant; or
(iv) the Company or any Subsidiary Guarantor shall fail to perform or
observe any other term, covenant or agreement contained in the Notes, any
Subsidiary Guarantee or the Indenture (other than a default specified in
(i), (ii) or (iii) above) for a period of 30 days after written notice of
such failure requiring the Company to remedy the same shall have been given
(x) to the Company by the Trustee or (y) to the Company and the Trustee by
the holders of at least 25% in aggregate principal amount of the Notes then
outstanding; or
(v) the occurrence and continuation beyond any applicable grace period
of any default in the payment of the principal of (or premium, if any, on)
or interest on any Indebtedness of the Company (other than the Notes) or
any Subsidiary Guarantor or any other Restricted Subsidiary for money
borrowed when due, or any other default causing acceleration of any
Indebtedness of the Company or any Subsidiary Guarantor or any other
Restricted Subsidiary for money borrowed, provided that the aggregate
principal amount of such Indebtedness shall exceed $5,000,000; provided
further that if any such default is cured or waived or any such
acceleration rescinded, or such debt is repaid, within a period of 10 days
from the continuation of such default beyond the applicable grace period or
the occurrence of such acceleration, as the case may be, such Event of
Default under the Indenture and any consequential acceleration of the Notes
shall be automatically rescinded, so long as such rescission does not
conflict with any judgment or decree; or
(vi) the commencement of proceedings, or the taking of any enforcement
action (including by way of set-off), by any holder of at least $5,000,000
in aggregate principal amount of Indebtedness of the Company or any
Subsidiary Guarantor or any other Restricted Subsidiary, after a default
under such Indebtedness, to retain in satisfaction of such Indebtedness or
to collect or seize, dispose of or apply in satisfaction of such
Indebtedness, property or assets of the Company or any Subsidiary Guarantor
or any other Restricted Subsidiary having a fair market value (as
determined by the Board of Directors of the Company and evidenced by a
board resolution) in excess of $5,000,000 individually or in the aggregate,
provided that if any such proceedings or actions are terminated or
rescinded, or such Indebtedness is repaid, such Event of Default under the
Indenture and any consequential acceleration of the Notes shall be
automatically rescinded, so long as (i) such rescission does not conflict
with any judgment or decree and (ii) the holder of such Indebtedness shall
not have applied any such property or assets in satisfaction of such
Indebtedness; or
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(vii) any Subsidiary Guarantee shall for any reason cease to be, or be
asserted by the Company or any Subsidiary Guarantor, as applicable, not to
be, in full force and effect, enforceable accordance with its terms (except
pursuant to the release of any such Subsidiary Guarantee in accordance with
the Indenture); or
(viii) certain events giving rise to ERISA liability; or
(ix) final judgments or orders rendered against the Company or any
Subsidiary Guarantor or any other Restricted Subsidiary that are
unsatisfied and that require the payment in money, either individually or
in an aggregate amount, that is more than $5,000,000 over the coverage
under applicable insurance policies and either (i) commencement by any
creditor of an enforcement proceeding upon such judgment (other than a
judgment that is stayed by reason of pending appeal or otherwise) or (ii)
the occurrence of a 60-day period during which a stay of such judgment or
order, by reason of pending appeal or otherwise, was not in effect; or
(x) the entry of a decree or order by a court having jurisdiction in
the premises (A) for relief in respect of the Company or any Subsidiary
Guarantor or any other Restricted Subsidiary in an involuntary case or
proceeding under any applicable federal or state bankruptcy, insolvency,
reorganization or other similar law or (B) adjudging the Company or any
Subsidiary Guarantor or any other Restricted Subsidiary bankrupt or
insolvent, or approving a petition seeking reorganization, arrangement,
adjustment or composition of the Company or a Restricted Subsidiary under
any applicable federal or state law, or appointing under any such law a
custodian, receiver, liquidator, assignee, trustee, sequestrator or other
similar official of the Company or any Subsidiary Guarantor or any other
Restricted Subsidiary or of a substantial part of their consolidated
assets, or ordering the winding up or liquidation of their affairs, and the
continuance of any such decree or order for relief or any such other decree
or order unstayed and in effect for a period of 60 consecutive days; or
(xi) the commencement by the Company or any Subsidiary Guarantor or
any other Restricted Subsidiary of a voluntary case or proceeding under any
applicable federal or state bankruptcy, insolvency, reorganization or other
similar law or any other case or proceeding to be adjudicated a bankruptcy
or insolvent, or the consent by the Company or any Subsidiary Guarantor or
any other Restricted Subsidiary to the entry of a decree or order for
relief in respect thereof in an involuntary case or proceeding under any
applicable federal or state bankruptcy, insolvency, reorganization or other
similar law or to the commencement of any bankruptcy or insolvency case or
proceeding against it, or the filing by the Company or any Subsidiary
Guarantor or any other Restricted Subsidiary of a petition or consent
seeking reorganization or relief under any applicable federal or state law,
or the consent by it under any such law to the filing of any such petition
or to the appointment of or taking possession by a custodian, receiver,
liquidator, assignee, trustee or sequestrator (or other similar official)
of any of the Company or any Subsidiary Guarantor or any other Restricted
Subsidiary or of any substantial part of their consolidated assets, or the
making by it of an assignment for the benefit of creditors under any such
law, or the admission by it in writing of its inability to pay its debts
generally as they become due or taking of corporate action by the Company
or any Subsidiary Guarantor or any other Restricted Subsidiary in
furtherance of any such action.
If an Event of Default (other than as specified in clause (x) or (xi)
above) shall occur and be continuing, the Trustee, by written notice to the
Company, or the holders of at least 25% in aggregate principal amount of the
Notes then outstanding, by notice to the Trustee and the Company, may declare
the principal of, premium, if any, and accrued interest on all of the
outstanding Notes due and payable immediately, upon which declaration all
amounts payable in respect of the Notes shall be immediately due and payable. If
an Event of Default specified in clause (x) or (xi) above occurs and is
continuing, then the principal of, premium, if any, and accrued interest on all
of the outstanding Notes shall ipso facto become and be immediately due and
payable without any declaration. notice or other act on the part of the Trustee
or any holder of Notes.
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After a declaration of acceleration under the Indenture, but before a
judgment or decree for payment of the money due has been obtained by the
Trustee, the holders of a majority in aggregate principal amount of the
outstanding Notes, by written notice to the Company and the Trustee, may rescind
such declaration if (a) the Company or any Subsidiary Guarantor has paid or
deposited with the Trustee a sum sufficient to pay (i) all sums paid or advanced
by the Trustee under the Indenture and the reasonable compensation, expenses,
disbursements and advances of the Trustee, its agents and counsel, (ii) all
overdue interest on all Notes, (iii) the principal of and premium, if any, on
any Notes which have become due otherwise than by such declaration of
acceleration and interest thereon at the rate home by the Notes, and (iv) to the
extent that payment of such interest is lawful, interest upon overdue interest
and overdue principal at the rate borne by the Notes which has become due
otherwise than by such declaration of acceleration; (b) the rescission would not
conflict with any judgment or decree of a court of competent jurisdiction; and
(c) all Events of Default, other than the nonpayment of principal of, premium,
if any, and interest on the Notes that has become due solely by such declaration
of acceleration, have been cured or waived.
The holders of not less than a majority in aggregate principal amount of
the outstanding Notes may on behalf of the holders of all the Notes waive any
past defaults under the Indenture, except a default in the payment of the
principal of, premium, if any, or interest on any Note, or in respect of a
covenant or provision which under the Indenture cannot be modified or amended
without the consent of the holder of each Note outstanding.
No holder of any of the Notes has any fight to institute any proceeding
with respect to the Indenture or any remedy thereunder, unless the holders of at
least 25% in aggregate principal amount of the outstanding Notes have made
written request, and offered reasonable indemnity, to the Trustee to institute
such proceeding as Trustee under the Notes and the Indenture, the Trustee has
failed to institute such proceeding within 60 days after receipt of such notice
and the Trustee, within such 60-day period, has not received directions
inconsistent with such written request by holders of a majority in aggregate
principal amount of the outstanding Notes. Such limitations do not apply,
however, to a suit instituted by a holder of a Note for the enforcement of the
payment of the principal of, premium, if any, or interest on such Note on or
after the respective due dates expressed in such Note.
During the existence of an Event of Default, the Trustee is required to
exercise such rights and powers vested in it under the Indenture and use the
same degree of care and skill in its exercise thereof as a prudent person would
exercise under the circumstances in the conduct of such person's own affairs.
Subject to the provisions of the Indenture relating to the duties of the
Trustee, in case an Event of Default shall occur and be continuing, the Trustee
under the Indenture is not under any obligation to exercise any of its fights or
powers under the Indenture at the request or direction of any of the Noteholders
unless such holders shall have offered to the Trustee reasonable security or
indemnity. Subject to certain provisions concerning the rights of the Trustee,
the holders of a majority in aggregate principal amount of the outstanding Notes
have the right to direct the time, method and place of conducting any proceeding
for any remedy available to the Trustee, or exercising any trust or power
conferred on the Trustee under the Indenture.
If a Default or an Event of Default occurs and is continuing and is known
to the Trustee, the Trustee shall mail to each holder of the Notes notice of the
Default or Event of Default within 60 days after the occurrence thereof. Except
in the case of a Default or an Event of Default in payment of principal of,
premium, if any, or interest on any Notes, the Trustee may withhold the notice
to the holders of such Notes if a committee of its Trust Officers in good faith
determines that withholding the notice is in the interest of the Noteholders.
The Company is required to furnish to the Trustee annual and quarterly
statements as to the performance by the Company and the Subsidiary Guarantors of
their respective obligations under the Indenture and as to any default in such
performance. The Company is also required to notify the Trustee within ten days
of any Default.
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LEGAL DEFEASANCE OR COVENANT DEFEASANCE OF INDENTURE
The Company may, at its option and at any time, terminate the obligations
of the Company and the Subsidiary Guarantors with respect to the outstanding
Notes ("legal defeasance"). Such legal defeasance means that the Company and the
Subsidiary Guarantors shall be deemed to have paid and discharged the entire
Indebtedness represented by the outstanding Notes, except for (i) the rights of
holders of outstanding Notes to receive payment in respect of the principal of,
premium, if any, on and interest on such Notes when such payments are due, (ii)
the Company's obligations to issue temporary Notes, register the transfer or
exchange of any Notes, replace mutilated, destroyed, lost or stolen Notes and
maintain an office or agency for payments in respect of the Notes, (iii) the
rights, powers, trusts, duties and immunities of the Trustee, and (iv) the
defeasance provisions of the Indenture. In addition, the Company may, at its
option and at any time, elect to terminate the obligations of the Company and
any Subsidiary Guarantor with respect to certain covenants that are set forth in
the Indenture, some of which are described under "--Certain Covenants" above,
and any omission to comply with such obligations shall not constitute a Default
or an Event of Default with respect to the Notes ("covenant defeasance").
In order to exercise either legal defeasance or covenant defeasance, (i)
the Company or any Subsidiary Guarantor must irrevocably deposit, with the
Trustee, in trust, for the benefit of the holders of the Notes, cash in United
States dollars, U.S. Government Obligations (as defined in the Indenture), or a
combination thereof, in such amounts as will be sufficient, in the opinion of a
nationally recognized firm of independent public accountants, to pay the
principal of, premium, if any, on and interest on the outstanding Notes to
redemption or maturity; (ii) the Company shall have delivered to the Trustee an
Opinion of Counsel to the effect that the holders of the outstanding Notes will
not recognize income, gain or loss for federal income tax purposes as a result
of such legal defeasance or covenant defeasance and will be subject to federal
income tax on the same amounts, in the same manner and at the same times as
would have been the case if such legal defeasance or covenant defeasance had not
occurred (in the case of legal defeasance, such opinion must refer to and be
based upon a published ruling of the Internal Revenue Service or a change in
applicable federal income tax laws); (iii) no Default or Event of Default shall
have occurred and be continuing on the date of such deposit; (iv) such legal
defeasance or covenant defeasance shall not cause the Trustee to have a
conflicting interest under the Indenture or the Trust Indenture Act with respect
to any securities of the Company or any Subsidiary Guarantor, (v) such legal
defeasance or covenant defeasance shall not result in a breach or violation of,
or constitute a default under, any material agreement or instrument to which the
Company or any Subsidiary Guarantor is a party or by which it is bound; and (vi)
the Company shall have delivered to the Trustee an Officers' Certificate and an
Opinion of Counsel satisfactory to the Trustee, which, taken together, state
that all conditions precedent under the Indenture to either legal defeasance or
covenant defeasance, as the case may be, have been complied with and that no
violations under agreements governing any other outstanding Indebtedness would
result therefrom.
SATISFACTION AND DISCHARGE
The Indenture will be discharged and will cease to be of further effect
(except as to surviving rights or registration of transfer or exchange of the
Notes, as expressly provided for in the Indenture) as to all outstanding Notes
when (i) either (a) all the Notes theretofore authenticated and delivered
(except lost, stolen or destroyed Notes which have been replaced or paid and
Notes for whose payment money has theretofore been deposited in trust or
segregated and held in trust by the Company and thereafter repaid to the Company
or discharged from such trust) have been delivered to the Trustee for
cancellation or (b) all Notes not theretofore delivered to the Trustee for
cancellation have become due and payable or will become due and payable at their
Stated Maturity within one year, or are to be called for redemption within one
year under arrangements satisfactory to the Trustee for the serving of notice of
redemption by the Trustee in the name, and at the expense, of the Company, and
the Company has irrevocably deposited or caused to be deposited with the Trustee
funds in an amounts sufficient to pay and discharge the entire indebtedness on
the Notes not theretofore delivered to the Trustee for cancellation, for
principal of (and premium, if any, on) and interest on the Notes to the date of
deposit (in the case of Notes which have become due and payable) or to the
Stated Maturity or Redemption Date, as the case may be, together with
instructions from the Company irrevocably
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directing the Trustee to apply such funds to the payment thereof at maturity or
redemption, as the case may be, (ii) the Company has paid all other sums payable
under the Indenture by the Company; and (iii) the Company has delivered to the
Trustee an Officers' Certificate and an Opinion of Counsel satisfactory to the
Trustee, which, taken together, state that all conditions precedent under the
Indenture relating to the satisfaction and discharge of the Indenture have been
complied with.
AMENDMENTS AND WAIVERS
From time to time, the Company and the Trustee may, without the consent of
the Noteholders, amend, waive or supplement the Indenture or the Notes for
certain specified purposes, including, among other things, curing ambiguities,
defects or inconsistencies, qualifying, or maintaining the qualification of, the
Indenture under the Trust Indenture Act of 1939, or making any change that does
not adversely affect the rights of any Noteholder. Other amendments and
modifications of the Indenture or the Notes may be made by the Company, the
Subsidiary Guarantors and the Trustee with the consent of the holders of not
less than a majority of the aggregate principal amount of the outstanding Notes;
provided, however, that no such modification or amendment may, without the
consent of the holder of each outstanding Note affected thereby, (a) change the
Stated Maturity of the principal of, or any installment of interest on any Note,
(b) reduce the principal amount of (or the premium, if any, on) or interest on
any Note, (c) change the place, coin or currency of payment of principal of (or
the premium, if any, on) or interest on, any Note, (d) impair the right to
institute suit for the enforcement of any payment on or with respect to any
Note, (e) reduce the above-stated percentage of aggregate principal amount of
outstanding Notes necessary to modify or amend the Indenture, (f) reduce the
percentage of aggregate principal amount of outstanding Notes necessary for
waiver of compliance with certain provisions of the Indenture or for waiver of
certain defaults, (g) modify any provisions of the Indenture relating to the
modification and amendment of the Indenture or the waiver of past defaults or
covenants, except as otherwise specified, or (h) amend, change or modify the
obligation of the Company to make and consummate a Change of Control Offer in
the event of a Change of Control or make and consummate the Net Proceeds Offer
with respect to any Asset Sale or modify any of the provisions or definitions
with respect thereto.
The Holders of a majority in aggregate principal amount of the outstanding
Notes may waive compliance by the Company with certain restrictive provisions of
the Indenture. The Holders of a majority in aggregate principal amount of the
outstanding Notes may waive any past default under the Indenture, except a
default in the payment of principal (or premium, if any, on) or interest on the
Notes.
THE TRUSTEE
The Indenture provides that, except during the continuance of an Event of
Default, the Trustee thereunder will perform only such duties as are
specifically set forth in the Indenture. If an Event of Default has occurred and
is continuing, the Trustee will exercise such rights and powers vested in it
under the Indenture and use the same degree of care and skill in its exercise as
a prudent Person would exercise under the circumstances in the conduct of such
Person's own affairs.
The Indenture and provisions of the Trust Indenture Act of 1939, as
amended, incorporated by reference therein contain limitations on the rights of
the Trustee thereunder, should it become a creditor of the Company, to obtain
payment of claims in certain cases or to realize on certain property received by
it in respect of any such claims, as security or otherwise. The Trustee is
permitted to engage in other transactions; provided, however, that if it
acquires any conflicting interest (as defined) it must eliminate such conflict
or resign.
GOVERNING LAW
The Indenture, the Notes and the Subsidiary Guarantees provide that they
will be governed by the laws of the State of New York, without regard to the
principles of conflicts of law.
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CERTAIN DEFINITIONS
"Acquired Indebtedness" means Indebtedness of a Person (a) assumed in
connection with an Asset Acquisition from such Person, (b) outstanding at the
time such Person becomes a Subsidiary of any other Person (other than any
Indebtedness incurred in connection with, or in contemplation of, such Asset
Acquisition or such Person becoming such a Subsidiary) or (c) any renewals,
extensions, substitutions, refinancings or replacements (each, for purposes of
this clause, a "refinancing") by the Company of any Indebtedness described in
clause (a) or (b) of this definition, including any successive refinancings, so
long as (A) any such new Indebtedness shall be in a principal amount that does
not exceed the principal amount (or, if such Indebtedness being refinanced
provides for an amount less than the principal amount thereof to be due and
payable upon a declaration of acceleration thereof, such lesser amount as of the
date of determination) so refinanced plus the amount of any premium required to
be paid in connection with such refinancing pursuant to the terms of the
Indebtedness refinanced or the amount of any premium reasonably determined by
the Company as necessary to accomplish such refinancing, plus the amount of
expenses of the Company incurred in connection with such refinancing, and (B) in
the case of any refinancing of Subordinated Indebtedness, such new Indebtedness
is made subordinate to the Notes at least to the same extent as the Indebtedness
being refinanced and (C) such new Indebtedness has an Average Life longer than
the Average Life of the Notes and a final Stated Maturity later than the final
Stated Maturity of the Notes.
"Adjusted Consolidated Net Tangible Assets" means (without duplication), as
of the date of determination, (a) the sum of (i) discounted future net revenues
from proved oil and gas reserves of the Company and its Restricted Subsidiaries
calculated in accordance with SEC guidelines before any state or federal income
taxes, as estimated by a nationally recognized firm of independent petroleum
engineers in a reserve report prepared as of the end of the Company's most
recently completed fiscal year, as increased by, as of the date of
determination, the estimated discounted future net revenues from (A) estimated
proved oil and gas reserves acquired since the date of such year-end reserve
report, and (B) estimated oil and gas reserves attributable to upward revisions
of estimates of proved oil and gas reserves since the date of such year-end
reserve report due to exploration, development or exploitation activities, in
each case calculated in accordance with SEC guidelines (utilizing the prices
utilized in such year-end reserve report), and decreased by, as of the date of
determination, the estimated discounted future net revenues from (C) estimated
proved oil and gas reserves produced or disposed of since the date of such
year-end reserve report and (D) estimated oil and gas reserves attributable to
downward revisions of estimates of proved oil and gas reserves since the date of
such year-end reserve report due to changes in geological conditions or other
factors which would, in accordance with standard industry practice, cause such
revisions, in each case calculated in accordance with SEC guidelines (utilizing
the prices utilized in such year-end reserve report); provided that, in the case
of each of the determinations made pursuant to clauses (A) through (D), such
increases and decreases shall be as estimated by the Company's petroleum
engineers, unless in the event that there is a Material Change as a result of
such acquisitions, dispositions or revisions, then the discounted future net
revenues utilized for purposes of this clause (a)(i) shall be confirmed in
writing by a nationally recognized firm of independent petroleum engineers, (ii)
the capitalized costs that are attributable to oil and gas properties of the
Company and its Restricted Subsidiaries to which no proved oil and gas reserves
are attributable, based on the Company's books and records as of a date no
earlier than the date of the Company's latest annual or quarterly financial
statements, (iii) the Net Working Capital on a date no earlier than the date of
the Company's latest annual or quarterly financial statements and (iv) the
greater of (i) the net book value on a date no earlier than the date of the
Company's latest annual or quarterly financial statements or (ii) the appraised
value, as estimated by independent appraisers, of other tangible assets
(including, without duplication, Investments in unconsolidated Restricted
Subsidiaries) of the Company and its Restricted Subsidiaries, as of the date no
earlier than the date of the Company's latest audited financial statements,
minus (b) the sum of (i) minority interests, (ii) any gas balancing liabilities
of the Company and its Restricted Subsidiaries reflected in the Company's latest
audited financial statements, (iii) to the extent included in (a)(i) above, the
discounted future net revenues, calculated in accordance with SEC guidelines
(utilizing the prices utilized in the Company's year-end reserve report),
attributable to reserves which are required to be delivered to third parties to
fully satisfy the obligations of the Company and its Restricted Subsidiaries
with respect to Volumetric Production Payments on the schedules specified with
respect thereto and (iv) the discounted future net revenues, calculated in
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accordance with SEC guidelines, attributable to reserves subject to
Dollar-Denominated Production Payments which, based on the estimates of
production and price assumptions included in determining the discounted future
net revenues specified in (a)(i) above, would be necessary to fully satisfy the
payment obligations of the Company and its Restricted Subsidiaries with respect
to Dollar-Denominated Production Payments on the schedules specified with
respect thereto. If the Company changes its method of accounting from the full
cost method to the successful efforts method or a similar method of accounting,
"Adjusted Consolidated Net Tangible Assets" will continue to be calculated as if
the Company was still using the full cost method of accounting.
"Adjusted Net Assets" of a Subsidiary Guarantor at any date shall mean the
amount by which the fair value of the properties and assets of such Subsidiary
Guarantor exceeds the total amount of liabilities, including, without
limitation, contingent liabilities (after giving effect to all other fixed and
contingent liabilities incurred or assumed on such date), but excluding
liabilities under the Subsidiary Guarantee, of such Subsidiary Guarantor at such
date.
"Affiliate" means, with respect to any specified Person, any other Person
directly or indirectly controlling or controlled by or under direct or indirect
common control with such specified Person. For the purposes of this definition,
"control," when used with respect to any person, means the power to direct the
management and policies of such Person, directly or indirectly, whether through
the ownership of voting securities, by contract or otherwise; and the terms
"controlling" and "controlled" have meanings correlative to the foregoing. For
purposes of this definition, beneficial ownership of 10% or more of the voting
common equity (on a fully diluted basis) or options or warrants to purchase such
equity (but only if exercisable at the date of determination or within 60 days
thereof) of a Person shall be deemed to constitute control of such Person.
"Asset Acquisition" means (a) an Investment by the Company or any
Restricted Subsidiary in any other Person pursuant to which such Person shall
become a Restricted Subsidiary or any Restricted Subsidiary shall be merged with
or into the Company or any other Restricted Subsidiary or (b) the acquisition by
the Company or any Restricted Subsidiary of the assets of any Person which
constitute all or substantially all of the assets of such Person or any division
or line of business of such Person.
"Asset Sale" means any sale, issuance, conveyance, transfer, lease or other
disposition to any Person other than the Company or any of its Restricted
Subsidiaries (including, without limitation, by means of a Sale/Leaseback
Transaction or by way of merger or consolidation) (collectively, for purposes of
this definition, a "transfer"), directly or indirectly, in one or a series of
related transactions, of (a) any Capital Stock of any Restricted Subsidiary held
by the Company or any Restricted Subsidiary; (b) all or substantially all of the
properties and assets of any division or line of business of the Company or any
of its Restricted Subsidiaries; or (c) any other properties or assets of the
Company or any of its Restricted Subsidiaries other than a disposition of
hydrocarbons or other mineral products in the ordinary course of business. For
the purposes of this definition, the term "Asset Sale" shall not include (i) any
transfer of properties or assets that is governed by, and made in accordance
with, the provisions described under "Merger, Consolidation and Sale of Assets;"
(ii) any transfer of properties or assets to an Unrestricted Subsidiary, if
permitted under the "Limitation on Restricted Payments" Covenant; (iii) any
trade or exchange by the Company or any Restricted Subsidiary of oil and gas
properties (other than properties constituting all or substantially all of the
Original Properties) for other oil and gas properties owned or held by another
Person provided that (x) the fair market value of the properties traded or
exchanged by the Company or such Restricted Subsidiary (including any cash or
Cash Equivalents, not to exceed 15% of such fair market value, to be delivered
by the Company or such Restricted Subsidiary) is reasonably equivalent to the
fair market value of the properties (together with any cash or Cash Equivalents,
not to exceed 15% of such fair market value) to be received by the Company or
such Restricted Subsidiary as determined in good faith by (i) any officer of the
Company if such fair market value is less than $5 million and (ii) the Board of
Directors of the Company as certified by a certified resolution delivered to the
Trustee if such fair market value is equal to or in excess of $5 million;
provided that if such resolution indicates that such fair market value is equal
to or in excess of $10 million such resolution shall be accompanied by a written
appraisal by a nationally recognized investment banking firm or appraisal firm,
in each case specializing or having a speciality in oil and gas properties, and
(y) such exchange is
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approved by a majority of the Disinterested Directors of the Company; or (iv)
any transfer of Properties having a fair market value of less than $2,000,000.
"Attributable Indebtedness" means, with respect to any particular lease
under which any Person is at the time liable and at any date as of which the
amount thereof is to be determined, the present value of the total net amount of
rent required to be paid by such Person under the lease during the primary term
thereof, without giving effect to any renewals at the option of the lessee,
discounted from the respective due dates thereof to such date of determination
at the rate of interest per annum implicit in the terms of the lease. As used in
the preceding sentence, the "net amount of rent" under any lease for any such
period shall mean the sum of rental and other payments required to be paid with
respect to such period by the lessee thereunder, excluding any amounts required
to be paid by such lessee on account of maintenance and repairs, insurance,
taxes, assessments, water rates or similar charges. In the case of any lease
which is terminable by the lessee upon payment of a penalty, such net amount of
rent shall also include the amount of such penalty, but no rent shall be
considered as required to be paid under such lease subsequent to the first date
upon which it may be so terminated.
"Average Life" means, with respect to any Indebtedness, as at any date of
determination, the quotient obtained by dividing (a) the sum of the products of
(i) the number of years (and any portion thereof) from the date of determination
to the date or dates of each successive scheduled principal payment (including,
without limitation, any sinking fund or mandatory redemption payment
requirements) of such Indebtedness multiplied by (ii) the amount of each such
principal payment by (b) the sum of all such principal payments.
"Capital Stock" means, with respect to any Person, any and all shares,
interests, participations, rights in or other equivalents in the equity
interests (however designated) in such Person, and any rights (other than debt
securities convertible into an equity interest), warrants or options exercisable
for, exchangeable for or convertible into such an equity interest in such
Person.
"Capitalized Lease Obligation" means any obligation to pay rent or other
amounts under a lease of (or other agreement conveying the right to use) any
property (whether real, personal or mixed) that is required to be classified and
accounted for as a capital lease obligation under GAAP, and, for the purpose of
the Indenture, the amount of such obligation at any date shall be the
capitalized amount thereof at such date, determined in accordance with GAAP.
"Cash Equivalents" means (i) any evidence of Indebtedness with a maturity
of 365 days or less issued or directly and fully guaranteed or insured by the
United States of America or any agency or instrumentality thereof (provided that
the full faith and credit of the United States of America is pledged in support
thereof); (ii) demand and time deposits and certificates of deposit or
acceptances with a maturity of 365 days or less of any financial institution
that is a member of the Federal Reserve System having combined capital and
surplus and undivided profits of not less than $500,000,000; (iii) commercial
paper with a maturity of 365 days or less issued by a corporation that is not an
Affiliate of the Company and is organized under the laws of any state of the
United States or the District of Columbia and rated at least A-1 by S&P or at
least P-1 by Moody's; (iv) repurchase obligations with a term of not more than
seven days for underlying securities of the types described in clause (i) above
entered into with any commercial bank meeting the specifications of clause (ii)
above; and (v) overnight bank deposits and bankers' acceptances at any
commercial bank meeting the qualifications specified in clause (ii) above.
"Change of Control" means the occurrence of any of the following events:
(a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d)
of the Exchange Act) other than the F&R Interests is or becomes the "beneficial
owner" (as defined in Rule 13d-3 under the Exchange Act), directly or
indirectly, of more than 50% of the total Voting Stock of the Company; (b) the
Company is merged with or into or consolidated with another Person and,
immediately after giving effect to the merger or consolidation, (A) less than
50% of the total voting power of the outstanding Voting Stock of the surviving
or resulting Person is then "beneficially owned" (within the meaning of Rule
13d-3 under the Exchange Act) in the aggregate by (x) the stockholders of the
Company immediately prior to such merger or consolidation, or (y) if a record
date has been set to determine the stockholders of the Company entitled to vote
with respect to such merger or consolidation, the stockholders of the Company as
of such record date and (B) any "person" or "group"
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(as defined in Section 13(d)(3) or 14(d)(2) of the Exchange Act, other than the
F&R Interests, has become the direct or indirect "beneficial owner" (as defined
in Rule 13d-3 under the Exchange Act) of more than 50% of the total voting power
of the Voting Stock of the surviving or resulting Person; (c) the Company,
either individually or in conjunction with one or more Restricted Subsidiaries,
sells, conveys, transfers or leases, or the Restricted Subsidiaries sells,
convey, transfer or lease, all or substantially all of the assets of the Company
and the Restricted Subsidiaries, taken as a whole (either in one transaction or
a series of related transactions), including Capital Stock of the Restricted
Subsidiaries, to any Person (other than the Company or a Wholly Owned Restricted
Subsidiary); (d) during any consecutive two-year period, individuals who at the
beginning of such period constituted the Board of Directors of the Company
(together with any new directors whose election by such Board of Directors or
whose nomination for election by the stockholders of the Company was approved by
a vote of 66 2/3% of the directors then still in office who were either
directors at the beginning of such period or whose election or nomination for
election was previously so approved) cease for any reason to constitute a
majority of the Board of Directors of the Company then in office; or (e) the
liquidation or dissolution of the Company.
"Common Stock" of any Person means Capital Stock of such Person that does
not rank prior, as to the payment of dividends or as to the distribution of
assets upon any voluntary or involuntary liquidation, dissolution or winding up
of such Person, to shares of Capital Stock of any other class of such Person.
"Consolidated Fixed Charge Coverage Ratio" means, for any period, the ratio
of (a) the sum of Consolidated Net Income, Consolidated Interest Expense,
Consolidated Income Tax Expense and Consolidated Non-cash Charges deducted in
computing Consolidated Net Income, in each case, for such period, of the Company
and its Restricted Subsidiaries on a consolidated basis, all determined in
accordance with GAAP, decreased (to the extent included in determining
Consolidated Net Income) by the sum of (x) the amount of deferred revenues that
are amortized during such period and are attributable to reserves that are
subject to Volumetric Production Payments and (y) amounts recorded in accordance
with GAAP as repayments of principal and interest pursuant to Dollar-Denominated
Production Payments, to (b) the sum of such Consolidated Interest Expense for
such period; provided that (i) in making such computation, the Consolidated
Interest Expense attributable to interest on any Indebtedness required to be
computed on a pro forma basis in accordance with clause (x) of the "Limitation
on Indebtedness" covenant and bearing a floating interest rate shall be computed
as if the rate in effect on the date of computation had been the applicable rate
for the entire period, (ii) in making such computation, the Consolidated
Interest Expense attributable to interest on any Indebtedness under a revolving
credit facility required to be computed on a pro forma basis in accordance with
clause (x) of the "Limitation on Indebtedness" covenant shall be computed based
upon the average daily balance of such Indebtedness during the applicable
period, provided that such average daily balance shall be reduced by the amount
of any repayment of Indebtedness under a revolving credit facility during the
applicable period, which repayment permanently reduced the commitments or
amounts available to be reborrowed under such facility, (iii) notwithstanding
clauses (i) and (ii) of this proviso, interest on Indebtedness determined on a
fluctuating basis, to the extent such interest is covered by agreements relating
to Interest Rate Protection Obligations, shall be deemed to have accrued at the
rate per annum resulting after giving effect to the operation of such agreements
and (iv) in making such calculation, Consolidated Interest Expense shall exclude
interest attributable to Dollar-Denominated Production Payments.
"Consolidated Income Tax Expense" means, for any period, the provision for
federal, state, local and foreign income taxes of the Company and its Restricted
Subsidiaries for such period as determined on a consolidated basis in accordance
with GAAP.
"Consolidated Interest Expense" means, for any period, without duplication,
the sum of (i) the interest expense of the Company and its Restricted
Subsidiaries for such period as determined on a consolidated basis in accordance
with GAAP, including, without limitation, (a) any amortization of debt discount,
(b) the net cost under Interest Rate Protection Obligations (including any
amortization of discounts), (c) the interest portion of any deferred payment
obligation, (d) all commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing and (e) all
accrued interest, in each case to the extent attributable to such period, (ii)
to the extent any Indebtedness of any Person (other than the
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Company or a Restricted Subsidiary) is guaranteed by the Company or any
Restricted Subsidiary, the aggregate amount of interest paid or accrued by such
other Person during such period attributable to any such Indebtedness, in each
case to the extent attributable to that period, (iii) the aggregate amount of
the interest component of Capitalized Lease Obligations paid, accrued and/or
scheduled to be paid or accrued by the Company and its Restricted Subsidiaries
during such period as determined on a consolidated basis in accordance with GAAP
and (iv) the aggregate amount of dividends paid or accrued on Redeemable Capital
Stock or Preferred Stock of the Company and its Restricted Subsidiaries, to the
extent such Redeemable Capital Stock or Preferred Stock is owned by Persons
other than Restricted Subsidiaries.
"Consolidated Net Income" means, for any period, the consolidated net
income (or loss) of the Company and its Restricted Subsidiaries for such period
as determined in accordance with GAAP, adjusted by excluding (a) net after-tax
extraordinary gains or losses (less all fees and expenses relating thereto), (b)
net after-tax gains or losses (less all fees and expenses relating thereto)
attributable to Asset Sales, (c) the net income (or net loss) of any Person
(other than the Company or any of its Restricted Subsidiaries), in which the
Company or any of its Restricted Subsidiaries has an ownership interest, except
to the extent of the amount of dividends or other distributions actually paid to
the Company or its Restricted Subsidiaries in cash by such other Person during
such period (regardless of whether such cash dividends, distributions or
interest on indebtedness is attributable to net income (or net loss) of such
Person during such period or during any prior period), (d) net income (or net
loss) of any Person combined with the Company or any of its Restricted
Subsidiaries on a "pooling of interests" basis attributable to any period prior
to the date of combination, (e) the net income of any Restricted Subsidiary to
the extent that the declaration or payment of dividends or similar distributions
by that Restricted Subsidiary is not at the date of determination permitted,
directly or indirectly, by operation of the terms of its charter or any
agreement, instrument, judgment, decree, order, statute, rule or governmental
regulation applicable to that Restricted Subsidiary or its stockholders, (f)
income resulting from transfers of assets received by the Company or any
Restricted Subsidiary from an Unrestricted Subsidiary and (g) any write-downs of
non-current assets, provided, however, that any ceding limitation write downs
under SEC guidelines shall be treated as capitalized costs, as if such write
downs had not occurred.
"Consolidated Net Worth" means, at any date, the consolidated stockholders'
equity of the Company less the amount of such stockholders' equity attributable
to Redeemable Capital Stock or treasury stock of the Company and its Restricted
Subsidiaries, as determined in accordance with GAAP.
"Consolidated Non-cash Charges" means, for any period, the aggregate
depreciation, depletion, amortization and other non-cash expenses of the Company
and its Restricted Subsidiaries reducing Consolidated Net Income for such
period, determined on a consolidated basis in accordance with GAAP (excluding
any such non-cash charge which requires an accrual of or reserve for cash
charges for any future period).
"Credit Agreement" means the Revolving Credit Facility Agreement dated as
of December 7, 1994 among the Company and Chase Manhattan Bank, N.A., as agent,
as such agreement may be amended, modified, supplemented, extended, restated,
replaced (including replacement after the termination of such agreement),
restructured, increased, renewed or refinanced from time to time in one or more
credit agreements, loan agreements, instruments or similar agreements, as such
may be further amended, modified, supplemented, extended, restated, replaced
(including replacement after the termination of such agreement), restructured,
increased, renewed or refinanced from time to time, in each case in accordance
with and as permitted by the Indenture.
"Credit Agreement Obligations" means all monetary obligations of every
nature of the Company or a Restricted Subsidiary, including without limitation,
obligations to pay principal and interest, reimbursement obligations under
letters of credit, fees, expenses and indemnities, from time to time owed to the
lenders or any agent under or in respect of the Credit Agreement.
"Default" means any event. act or condition that is, or after notice or
passage of time or both would be, an Event of Default.
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"Designated Senior Indebtedness" means (i) all Senior Indebtedness under
the Credit Agreement Obligations (ii) all Senior Indebtedness under the Senior
Note Obligations and (iii) any other Senior Indebtedness which (a) at the time
of incurrence equals or exceeds $10,000,000 in aggregate principal amount and
(b) is specifically designated by the Company in the instrument evidencing such
Senior Indebtedness as "Designated Senior Indebtedness" for purpose of the
Indenture.
"Disinterested Director" means, with respect to any transaction or series
of transactions in respect of which the Board of Directors of the Company is
required to deliver a resolution of the Board of Directors under the Indenture,
a member of the Board of Directors of the Company who does not have any material
direct or indirect financial interest (other than an interest arising solely
from the beneficial ownership of Capital Stock of the Company) in or with
respect to such transaction or series of transactions.
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Event of Default" has the meaning set forth above under the caption
"Events of Default."
"F&R Interests" means, collectively, William W. Rucks, IV and James C.
Flores, together with their respective spouses, lineal descendants and
ascendants, heirs, executors or other legal representatives and any trusts
established for the benefit of the foregoing, or any other Person in which the
Persons referred to in the foregoing are at the time of determination the direct
record and beneficial owners of all of the outstanding Capital Stock.
"GAAP" means generally accepted accounting principles, consistently
applied, that are set forth in the opinions and pronouncements of the Accounting
Principles Board of the American Institute of Certified Public Accountants and
statements and pronouncements of the Financial Accounting Standards Board or in
such other statements by such other entity as may be approved by a significant
segment of the accounting profession of the United States of America, which are
applicable as of the date of the Indenture. "guarantee" means, as applied to any
obligation, (i) a guarantee (other than by endorsement of negotiable instruments
for collection in the ordinary course of business), direct or indirect, in any
manner, of any part or all of such obligation and (ii) an agreement, direct or
indirect, contingent or otherwise, the practical effect of which is to assure in
any way the payment or performance (or payment of damages in the event of
nonperformance) of all or any part of such obligation, including, without
limiting the foregoing, the payment of amounts drawn down by letters of credit.
When used as a verb, "guarantee" shall have a corresponding meaning.
"Guarantor Senior Indebtedness" means all Indebtedness of a Subsidiary
Guarantor (present and future) created, incurred, assumed or guaranteed by such
Subsidiary Guarantor (and all renewals, substitutions, refinancings or
replacements thereof) (including the principal of, interest on and fees,
premiums, expenses (including costs of collection), indemnities and other
amounts payable in connection with such Indebtedness) (and including, in the
case of the Credit Agreement and any guarantees related to the Senior Notes,
interest accruing after the filing of a petition by or against such Subsidiary
Guarantor under any bankruptcy law, in accordance with and at the rate,
including any default rate, specified with respect to such indebtedness, whether
or not a claim for such interest is allowed as a claim after such filing in any
proceeding under such bankruptcy law), unless the instrument governing such
Indebtedness expressly provides that such Indebtedness is not senior in right of
payment to its Subsidiary Guarantee. Notwithstanding the foregoing, Guarantor
Senior Indebtedness of a Subsidiary Guarantor will not include (i) Indebtedness
of such Subsidiary Guarantor evidenced by its Subsidiary Guarantee, (ii)
Indebtedness of such Subsidiary Guarantor that is expressly subordinate or
junior in right of payment to any Guarantor Senior Indebtedness of such
Subsidiary Guarantor or its Subsidiary Guarantee, (iii) Indebtedness which, when
incurred and without respect to any election under Section 1111(b) of Title 11
United States Code, is by its terms without recourse to such Subsidiary
Guarantor, (iv) any repurchase, redemption or other obligation in respect of
Redeemable Capital Stock of such Subsidiary Guarantor, (v) to the extent it
might constitute Indebtedness, any liability for federal, state, local or other
taxes owed or owing by such Subsidiary Guarantor, (vi) Indebtedness of such
Subsidiary Guarantor to the Company or any of the Company's other Subsidiaries
or any other Affiliate of the Company or any of such Affiliate's Subsidiaries,
and (vii) that portion of any Indebtedness of such Subsidiary Guarantor which at
the time of issuance is issued in violation of the Indenture (but, as to any
such
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Indebtedness, no such violation shall be deemed to exist for purposes of this
clause (vii) if the holder(s) of such Indebtedness or their representative or
such Subsidiary Guarantor shall have furnished to the Trustee an opinion of
counsel unqualified in all material respects of independent legal counsel,
addressed to the Trustee (which legal counsel may, as to matters of fact, rely
upon a certificate of such Subsidiary Guarantor) to the effect that the
incurrence of such Indebtedness does not violate the provisions of such
Indenture); provided that the foregoing exclusions shall not affect the
priorities of any Indebtedness arising solely by operation of law in any case or
proceeding or similar event described in clause (a), (b) or (c) of the second
paragraph of "--Subordination."
"Holder" means a Person in whose name a Note is registered in the Note
Register.
"Indebtedness" means, with respect to any Person, without duplication, (i)
all liabilities of such Person for borrowed money or for the deferred purchase
price of property or services, excluding any trade accounts payable and other
accrued current liabilities incurred in the ordinary course of business, but
including, without limitation, all obligations, contingent or otherwise, of such
Person in connection with any letters of credit, bankers' acceptance or other
similar credit transaction and in connection with any agreement to purchase,
redeem, exchange, convert or otherwise acquire for value any Capital Stock of
such Person, or any warrants, rights or options to acquire such Capital Stock,
now or hereafter outstanding, if, and to the extent, any of the foregoing would
appear as a liability upon a balance sheet of such Person prepared in accordance
with GAAP, (b) all obligations of such Person evidenced by bonds, notes,
debentures or other similar instruments, if, and to the extent, any of the
foregoing would appear as a liability upon a balance sheet of such Person
prepared in accordance with GAAP, (c) all Indebtedness of such Person created or
arising under any conditional sale or other title retention agreement with
respect to property acquired by such Person (even if the rights and remedies of
the seller or lender under such agreement in the event of default are limited to
repossession or sale of such property), but excluding trade accounts payable
arising in the ordinary course of business, (d) all Capitalized Lease
Obligations of such Person, (e) the Attributable Indebtedness (in excess of any
related Capitalized Lease Obligations) related to any Sale/Leaseback Transaction
of such Person, (f) all Indebtedness referred to in the preceding clauses of
other Persons and all dividends of other Persons, the payment of which is
secured by (or for which the holder of such Indebtedness has an existing right,
contingent or otherwise, to be secured by) any Lien upon property (including,
without limitation, accounts and contract rights) owned by such Person, even
though such Person has not assumed or become liable for the payment of such
Indebtedness (the amount of such obligation being deemed to be the lesser of the
value of such property or asset or the amount of the obligation so secured), (g)
all guarantees by such Person of Indebtedness referred to in this definition
(including, with respect to any Production Payment, any warranties or guaranties
of production or payment by such Person with respect to such Production Payment
but excluding other contractual obligations of such Person with respect to such
Production Payment), (h) all Redeemable Capital Stock of such Person valued at
the greater of its voluntary or involuntary maximum fixed repurchase price plus
accrued dividends, (i) all obligations of such Person under or in respect of
currency exchange contracts and Interest Rate Protection Obligations and (j) any
amendment, supplement, modification, deferral, renewal, extension or refunding
of any liability of such Person of the types referred to in clauses (a) through
(i) above. For purposes hereof, the "maximum fixed repurchase price" of any
Redeemable Capital Stock which does not have a fixed repurchase price shall be
calculated in accordance with the terms of such Redeemable Capital Stock as if
such Redeemable Capital Stock were purchased on any date on which Indebtedness
shall be required to be determined pursuant to the Indenture, and if such price
is based upon, or measured by, the fair market value of such Redeemable Capital
Stock, such fair market value shall be determined in good faith by the board of
directors of the issuer of such Redeemable Capital Stock, provided, however,
that if such Redeemable Capital Stock is not at the date of determination
permitted or required to be repurchased, the "maximum fixed repurchase price"
shall be the book value of such Redeemable Capital Stock. Subject to clause (g)
of the first sentence of this definition, neither Dollar-Denominated Production
Payments nor Volumetric Production Payments shall be deemed to be Indebtedness.
"Interest Rate Protection Obligations" means the obligations of any Person
pursuant to any arrangement with any other Person whereby, directly or
indirectly, such person is entitled to receive from time to time periodic
payments calculated by applying either a floating or a fixed rate of interest on
a stated notional
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amount in exchange for periodic payments made by such Person calculated by
applying a fixed or a floating rate of interest on the same notional amount and
shall include, without limitation, interest rate swaps, caps, floors, collars
and similar agreements or arrangements designed to protect against or manage
such Person's and any of its Subsidiaries' exposure to fluctuations in interest
rates.
"Investment" means, with respect to any Person, any direct or indirect
advance, loan guarantee of Indebtedness or other extension of credit or capital
contribution to (by means of any transfer of cash or other property or assets to
others or any payment for property, assets or services for the account or use of
others), or any purchase or acquisition by such Person of any Capital Stock,
bonds, notes, debentures or other securities (including derivatives) or
evidences of Indebtedness issued by, any other Person. In addition, the fair
market value of the net assets of any Restricted Subsidiary at the time that
such Restricted Subsidiary is designated an Unrestricted Subsidiary shall be
deemed to be an "Investment" made by the Company in such Unrestricted Subsidiary
at such time. "Investments" shall exclude (a) extensions of trade credit on
commercially reasonable terms in accordance with normal trade practices and (b)
Interest Rate Protection Obligations entered into in the ordinary course of
business or as required by any Permitted Indebtedness or any Indebtedness
incurred in compliance with the "Limitation on Indebtedness" covenant, but only
to the extent that the notional principal amount of such Interest Rate
Protection Obligations does not exceed 105% of the principal amount of such
Indebtedness to which such Interest Rate Protection Obligations relate and (c)
bonds, notes, debentures or other securities received in compliance with the
"Limitation on Disposition of Proceeds of Asset Sales" covenant.
"Lien" means any mortgage, charge, pledge, lien (statutory or other),
security interest, hypothecation, assignment for security, claim, or preference
or priority or other encumbrance or similar agreement or preferential
arrangement of any kind or nature whatsoever (including, without limitation, any
agreement to give or grant a Lien or any lease, conditional sale or other title
retention agreement having substantially the same economic effect as any of the
foregoing) upon or with respect to any property of any kind. A Person shall be
deemed to own subject to a Lien any property which such Person has acquired or
holds subject to the interest of a vendor or lessor under any conditional sale
agreement, capital lease or other title retention agreement.
"Material Change" means an increase or decrease (excluding changes that
result solely from changes in prices) of more than 50% during a fiscal quarter
in the estimated discounted future net cash flows from proved oil and gas
reserves of the Company and its Restricted Subsidiaries, calculated in
accordance with clause (a) (i) of the definition of Adjusted Consolidated Net
Tangible Assets; provided, however, that the following will be excluded from the
calculation of Material Change: (i) any acquisitions during the quarter of oil
and gas reserves that have been estimated by a nationally recognized firm of
independent petroleum engineers and on which a report or reports exist and (ii)
any disposition of properties existing at the beginning of such quarter that
have been disposed of as provided in the "Limitation on Disposition of Proceeds
of Asset Sales" covenant.
"Maturity" means, with respect to any Note, the date on which any principal
of such Note becomes due and payable as therein or herein provided, whether at
the Stated Maturity with respect to such principal or by declaration of
acceleration, call for redemption or purchase or otherwise.
"Moody's" means Moody's Investors Service, Inc. and its successors.
"Net Cash Proceeds" means, with respect to any Asset Sale, the proceeds
thereof in the form of cash or Cash Equivalents including payments in respect of
deferred payment obligations when received in the form of cash or Cash
Equivalents (except to the extent that such obligations are financed or sold
with recourse to the Company or any Restricted Subsidiary), net of (i) brokerage
commissions and other fees and expenses (including fees and expenses of legal
counsel and investment banks) related to such Asset Sale, (ii) provisions for
all taxes payable as a result of such Asset Sale, (iii) amounts required to be
paid to any Person (other than the Company or any Restricted Subsidiary) owning
a beneficial interest in the assets subject to the Asset Sale and (iv)
appropriate amounts to be provided by the Company or any Restricted Subsidiary,
as the case may be, as a reserve required in accordance with GAAP consistently
applied against any liabilities associated with such Asset Sale and retained by
the Company or any Restricted Subsidiary, as the case may be, after such Asset
Sale, including, without limitation, pension and other post-employment benefit
liabilities, liabilities
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related to environmental matters and liabilities under any indemnification
obligations associated with such Asset Sale, all as reflected in an Officers'
Certificate delivered to the Trustee; provided, however, that any amounts
remaining after adjustments, revaluations or liquidations of such reserves shall
constitute Net Cash Proceeds.
"Net Working Capital" means (i) all current assets of the Company and its
Restricted Subsidiaries, minus (ii) all current liabilities of the Company and
its Restricted Subsidiaries, except current liabilities included in
Indebtedness, in each case as set forth in financial statements of the Company
prepared in accordance with GAAP.
"Non-Recourse Indebtedness" means Indebtedness or that portion of
Indebtedness of the Company incurred in connection with the acquisition by the
Company of any property or assets and as to which (a) the holders of such
Indebtedness agree that they will look solely to the property or assets so
acquired and securing such Indebtedness for payment on or in respect of such
Indebtedness and (b) no default with respect to such Indebtedness would permit
(after notice or passage of time or both), according to the terms thereof, any
holder of any Indebtedness of the Company or a Restricted Subsidiary to declare
a default on such Indebtedness or cause the payment thereof to be accelerated or
payable prior to its stated maturity.
"Note Register" means the register maintained by or for the Company in
which the Company shall provide for the registration of the Notes and of
transfer of the Notes.
"Oil and Gas Business" means (i) the acquisition, exploration, development,
operation and disposition of interests in oil, gas and other hydrocarbon
properties, (ii) the gathering, marketing, treating, processing, storage,
refining, selling and transporting of any production from such interests or
properties, (iii) any business relating to or arising from exploration for or
development, production, treatment, processing, storage, refining,
transportation or marketing of oil, gas and other minerals and products produced
in association therewith, and (iv) any activity necessary, appropriate or
incidental to the activities described in the foregoing clauses (i) through
(iii) of this definition.
"Pari Passu Indebtedness" means any Indebtedness of the Company that is
pari passu in right of payment to the Notes.
"Permitted Indebtedness" means any of the following:
(i) Indebtedness of the Company under one or more bank credit or
revolving credit facilities in an aggregate principal amount at any one
time outstanding not to exceed the greater of (A) $100 million and (B) an
amount equal to the sum of (x) $30 million and (y) 20% of Adjusted
Consolidated Net Tangible Assets determined as of the date of the
incurrence of such Indebtedness (such greater amount being referred to as
the "Adjusted Maximum Credit Amount") (plus interest and fees under such
facilities), less any amounts derived from Asset Sales and applied to the
required permanent reduction of Senior Indebtedness (and a permanent
reduction of the related commitment to lend or amount available to be
reborrowed in the case of a revolving credit facility) under such credit
facilities as contemplated by the "Disposition of Proceeds of Asset Sales"
covenant (the "Maximum Credit Amount") (with the Maximum Credit Amount to
be an aggregate maximum amount for the Company and all Restricted
Subsidiaries, pursuant to clause (i) of the definition of "Permitted
Subsidiary Indebtedness"), and any renewals, amendments, extensions,
supplements, modifications, deferrals, refinancings or replacements (each,
for purposes of this clause, a "refinancing") thereof by the Company,
including any successive refinancings thereof by the Company, so long as
the aggregate principal amount of any such new Indebtedness, together with
the aggregate principal amount of all other Indebtedness outstanding
pursuant to this clause (i) (and clause (i) of the definition of "Permitted
Subsidiary Indebtedness"), shall not at any one time exceed the Maximum
Credit Amount;
(ii) Indebtedness of the Company under the Notes;
(iii) Indebtedness of the Company outstanding on the date of the
Indenture (and not repaid or defeased with the proceeds of the offering of
the Notes and the concurrent offering of Common Stock by the Company);
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(iv) obligations of the Company pursuant to Interest Rate Protection
Obligations, but only to the extent such obligations do not exceed the
aggregate principal amount of the Indebtedness covered by such Interest
Rate Protection Obligations; obligations under currency exchange contracts
entered into in the ordinary course of business; and hedging arrangements
that the Company enters into in the ordinary course of business for the
purpose of protecting its production against fluctuations in oil or natural
gas prices;
(v) Indebtedness of the Company to any Restricted Subsidiaries;
(vi) in-kind obligations relating to net gas balancing positions
arising in the ordinary course of business and consistent with past
practice;
(vii) Indebtedness in respect of bid, performance or surety bonds
issued for the account of the Company or any Restricted Subsidiary in the
ordinary course of business, including guarantees and letters of credit
supporting such bid, performance, surety or other reimbursement obligations
(in each case other than for an obligation for money borrowed);
(viii) any renewals, extensions, substitutions, refinancings or
replacements (each, for purposes of this clause, a "refinancing") by the
Company of any Indebtedness of the Company other than Indebtedness incurred
pursuant to clauses (iv), (vii) and (viii) of this definition, including
any successive refinancings by the Company, so long as (A) any such new
Indebtedness shall be in a principal amount that does not exceed the
principal amount (or, if such Indebtedness being refinanced provides for an
amount less than the principal amount thereof to be due and payable upon a
declaration of acceleration thereof, such lesser amount as of the date of
determination) so refinanced plus the amount of any premium required to be
paid in connection with such refinancing pursuant to the terms of the
Indebtedness refinanced or the amount of any premium reasonably determined
by the Company as necessary to accomplish such refinancing, plus the amount
of expenses of the Company incurred in connection with such refinancing,
and (B) in the case of any refinancing of Subordinated Indebtedness, such
new Indebtedness is made subordinate to the Notes at least to the same
extent as the Indebtedness being refinanced and (C) such new Indebtedness
has an Average Life equal to or longer than the Average Life of the
Indebtedness being refinanced and a final Stated Maturity equal to or later
than the final Stated Maturity of the Indebtedness being refinanced;
(ix) Non-Recourse Indebtedness; and
(x) other Indebtedness of the Company and the Restricted Subsidiaries
that are Subsidiary Guarantors in an aggregate principal amount not in
excess of $25,000,000 at any one time outstanding.
"Permitted Investments" means any of the following: (i) Investments in Cash
Equivalents; (ii) Investments in the Company or any of its Restricted
Subsidiaries; (iii) Investments in an amount not to exceed $10,000,000 at any
one time outstanding; (iv) Investments by the Company or any of its Restricted
Subsidiaries in another Person, if as a result of such Investment (A) such other
Person becomes a Restricted Subsidiary of the Company; or (B) such other Person
is merged or consolidated with or into, or transfers or conveys all or
substantially all of its assets to, the Company or a Restricted Subsidiary, (v)
entry into operating agreements, joint ventures, partnership agreements, working
interests, royalty interests, mineral leases, processing agreements, farm-out
agreements, contracts for the sale, transportation or exchange of oil and
natural gas, unitization agreements, pooling arrangements, area of mutual
interest agreements or other similar or customary agreements, transactions,
properties, interests or arrangements, and Investments and expenditures in
connection therewith or pursuant thereto, in each case made or entered into in
the ordinary course of the Oil and Gas Business, excluding, however, Investments
in corporations; or (vi) entry into any hedging arrangements in the ordinary
course of business for the purpose of protecting the Company's or any Restricted
Subsidiary's production against fluctuations in oil or natural gas prices.
"Permitted Liens" means the following types of Liens:
(a) Liens existing as of the date the Notes are first issued;
(b) Liens securing the Notes;
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(c) Liens in favor of the Company or a Restricted Subsidiary that is a
Subsidiary Guarantor;
(d) Liens securing Senior Indebtedness or Guarantor Senior
Indebtedness;
(e) Liens for taxes, assessments and governmental charges or claims
either (i) not delinquent or (ii) contested in good faith by appropriate
proceedings and as to which the Company or its Restricted Subsidiaries
shall have set aside on its books such reserves as may be required pursuant
to GAAP;
(f) statutory Liens of landlords and Liens of carriers, warehousemen,
mechanics, suppliers, materialmen, repairmen and other Liens imposed by law
incurred in the ordinary course of business for sums not delinquent or
being contested in good faith, if such reserve or other appropriate
provision, if any, as shall be required by GAAP shall have been made in
respect thereof,
(g) Liens incurred or deposits made in the ordinary course of business
in connection with workers' compensation, unemployment insurance and other
types of social security, or to secure the payment or performance of
tenders, statutory or regulatory obligations, surety and appeal bonds,
bids, leases, government contracts and leases, performance and return of
money bonds and other similar obligations (exclusive of obligations for the
payment of borrowed money but including lessee or operator obligations
under statutes, governmental regulations or instruments related to the
ownership, exploration and production of oil, gas and minerals on state,
Federal or foreign lands or waters);
(h) judgment Liens not giving rise to an Event of Default so long as
any appropriate legal proceedings which may have been duly initiated for
the review of such judgment shall not have been finally terminated or the
period within which such proceeding may be initiated shall not have
expired;
(i) easements, rights-of-way, restrictions and other similar charges
or encumbrances not interfering in any material respect with the ordinary
conduct of the business of the Company or any of its Restricted
Subsidiaries;
(j) any interest or title of a lessor under any Capitalized Lease
Obligation or operating lease;
(k) Liens resulting from the deposit of funds or evidences of
Indebtedness in trust for the purpose of defeasing Indebtedness of the
Company or any of the Subsidiaries;
(l) Liens securing obligations under hedging agreements that the
Company or any Restricted Subsidiary enters into in the ordinary course of
business for the purpose of protecting its production against fluctuations
in oil or natural gas prices;
(m) Liens upon specific items of inventory or other goods and proceeds
of any Person securing such Person's obligations in respect of bankers'
acceptances issued or created for the account of such Person to facilitate
the purchase, shipment or storage of such inventory or other goods;
(n) Liens securing reimbursement obligations with respect to
commercial letters of credit which encumber documents and other property
relating to such letters of credit and products and proceeds thereof,
(o) Liens encumbering property or assets under construction arising
from progress or partial payments by a customer of the Company or its
Restricted Subsidiaries relating to such property or assets;
(p) Liens encumbering deposits made to secure obligations arising from
statutory, regulatory, contractual or warranty requirements of the Company
or any of its Restricted Subsidiaries, including rights of offset and
set-off;
(q) Liens securing Interest Rate Protection Obligations which Interest
Rate Protection Obligations relate to Indebtedness that is secured by Liens
otherwise permitted under this Indenture;
(r) Liens on, or related to, properties or assets to secure all or
part of the costs incurred in the ordinary course of business for the
exploration, drilling, development or operation thereof;
(s) Liens on pipeline or pipeline facilities which arise out of
operation of law;
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(t) Liens arising under operating agreements, joint venture
agreements, partnership agreements, oil and gas leases, farm-out
agreements, division orders, contracts for the sale, transportation or
exchange of oil and natural gas, unitization and pooling declarations and
agreements, area of mutual interest agreements and other agreements which
are customary in the Oil and Gas Business;
(u) Liens reserved in oil and gas mineral leases for bonus or rental
payments and for compliance with the terms of such leases;
(v) Liens constituting survey exceptions, encumbrances, casements, or
reservations of, or rights to others for, rights-of-way, zoning or other
restrictions as to the use of real properties, and minor defects of title
which, in the case of any of the foregoing, were not incurred or created to
secure the payment of borrowed money or the deferred purchase price of
Property or services, and in the aggregate do not materially adversely
affect the value of Property of the Company and the Restricted
Subsidiaries, taken as a whole, or materially impair the use of such
Properties for the purposes for which such Properties are held by the
Company or any Restricted Subsidiaries; and
(w) Liens securing Non-Recourse Indebtedness; provided, however, that
the related Non-Recourse Indebtedness shall not be secured by any property
or assets of the Company or any Restricted Subsidiary other than the
property and assets acquired by the Company with the proceeds of such
Non-Recourse Indebtedness;
Notwithstanding anything in clauses (a) through (w) of this definition, the term
"Permitted Liens" does not include any Liens resulting from the creation,
incurrence, issuance, assumption or guarantee of any Production Payments other
than Production Payments that are created, incurred, issued, assumed or
guaranteed in connection with the financing of, and within 30 days after, the
acquisition of the properties or assets that are subject thereto.
"Permitted Subsidiary Indebtedness" means any of the following:
(i) Indebtedness of any Restricted Subsidiary under one or more bank
credit or revolving credit facilities (and "refinancings" thereof) in an
amount at any one time outstanding not to exceed the Maximum Credit Amount
(in the aggregate for all Restricted Subsidiaries and the Company, pursuant
to clause (i) of the definition of "Permitted Indebtedness");
(ii) Indebtedness of any Restricted Subsidiary outstanding on the date
of the Indenture;
(iii) obligations of any Restricted Subsidiary pursuant to Interest
Rate Protection Obligations, but only to the extent such obligations do not
exceed the aggregate principal amount of the Indebtedness covered by such
Interest Rate Protection Obligations; and hedging arrangements that any
Restricted Subsidiary enters into in the ordinary course of business for
the purpose of protecting its production against fluctuations in oil or
natural gas prices;
(iv) the Subsidiary Guarantees of the Notes and Senior Notes (and any
assumption of the obligations guaranteed thereby);
(v) Indebtedness of any Restricted Subsidiary relating to guarantees
by such Restricted Subsidiary of Permitted Indebtedness pursuant to Clause
(i) of the definition of "Permitted Indebtedness;"
(vi) in-kind obligations relating to net gas balancing positions
arising in the ordinary course of business and consistent with past
practice;
(vii) Indebtedness in respect of bid, performance or surety bonds
issued for the account of any Restricted Subsidiary in the ordinary course
of business, including guarantees and letters of credit supporting such
bid, performance, surety or other reimbursement obligations (in each case
other than for an obligation for money borrowed);
(viii) Indebtedness of any Restricted Subsidiary to any other
Restricted Subsidiary or to the Company;
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(ix) Indebtedness relating to guarantees by any Restricted Subsidiary
permitted to be incurred pursuant to the "Limitation on Guarantees of
Indebtedness by Subsidiaries" covenant; and
(x) any renewals, extensions, substitutions, refinancings or
replacements (each, for purposes of this clause, a "refinancing") by any
Restricted Subsidiary of any Indebtedness of such Restricted Subsidiary,
including any successive refinancings by such Restricted Subsidiary, so
long as (x) any such new Indebtedness shall be in a principal amount that
does not exceed the principal amount (or, if such Indebtedness being
refinanced provides for an amount less than the principal amount thereof to
be due and payable upon a declaration of acceleration thereof, such lesser
amount as of the date of determination) so refinanced plus the amount of
any premium required to be paid in connection with such refinancing
pursuant to the terms of the Indebtedness refinanced or the amount of any
premium reasonably determined by such Restricted Subsidiary as necessary to
accomplish such refinancing, plus the amount of expenses of such Subsidiary
incurred in connection with such refinancing and (y) such new Indebtedness
has an Average Life equal to or longer than the Average Life of the
Indebtedness being refinanced and a final Stated Maturity equal to or later
than the final Stated Maturity of the Indebtedness being refinanced.
"Person" means any individual, corporation, limited liability company,
partnership, joint venture, association, joint stock company, trust,
unincorporated organization or government or any agency or political subdivision
thereof.
"Preferred Stock" means, with respect to any Person, any and all shares,
interests, participations or other equivalents (however designated) of such
Person's preferred or preference stock, whether now outstanding or issued after
the date of the Indenture, including, without limitation, all classes and series
of preferred or preference stock of such Person.
"Production Payments" means, collectively, Dollar-Denominated Production
Payments and Volumetric Production Payments.
"Qualified Capital Stock" of any Person means any and all Capital Stock of
such Person other than Redeemable Capital Stock.
"Redeemable Capital Stock" means any class or series of Capital Stock that,
either by its terms, by the terms of any security into which it is convertible
or exchangeable or by contract or otherwise, is, or upon the happening of an
event or passage of time would be, required to be redeemed prior to the final
Stated Maturity of the Notes or is redeemable at the option of the holder
thereof at any time prior to such final Stated Maturity, or is convertible into
or exchangeable for debt securities at any time prior to such final Stated
Maturity.
"Restricted Subsidiary" means any Subsidiary of the Company, whether
existing on or after the date of the Indenture, unless such Subsidiary of the
Company is an Unrestricted Subsidiary or is designated as an Unrestricted
Subsidiary pursuant to the terms of the Indenture.
"S&P" means Standard and Poor's Corporation and its successors.
"Sale/Leaseback Transaction" means, with respect to any Person, any direct
or indirect arrangement pursuant to which properties or assets are sold or
transferred by such Person or a Subsidiary of such Person and are thereafter
leased back from the purchaser or transferee thereof by such Person or one of
its Subsidiaries.
"Senior Indebtedness" means the principal of, premium, if any, and interest
on any Indebtedness of the Company (including, in the case of the Credit
Agreement and the Senior Notes, interest accruing after the filing of a petition
by or against the Company under any bankruptcy law, in accordance with and at
the rate, including any default rate, specified with respect to such
indebtedness, whether or not a claim for such interest is allowed as a claim
after such filing in any proceeding under such bankruptcy law), whether
outstanding on the date of the Indenture or thereafter created, incurred or
assumed, unless, in the case of any particular Indebtedness, the instrument
creating or evidencing the same or pursuant to which the same is outstanding
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<PAGE> 91
expressly provides that such Indebtedness shall not be senior in right of
payment to the Notes. Without limiting the generality of the foregoing, "Senior
Indebtedness" shall also include the Senior Note Obligations. Notwithstanding
the foregoing, "Senior Indebtedness" shall not include (a) Indebtedness
evidenced by the Notes, (b) Indebtedness that is expressly subordinate or junior
in right of payment to any Senior Indebtedness of the Company, (c) Indebtedness
which, when incurred and without respect to any election under Section 1111(b)
of Title 11 United States Code, is by its terms without recourse to the Company,
(d) any repurchase, redemption or other obligation in respect of Redeemable
Capital Stock of the Company, (e) to the extent it might constitute
Indebtedness, any liability for federal, state, local or other taxes owed or
owing by the Company, (f) Indebtedness of the Company to a Subsidiary of the
Company or any other Affiliate of the Company or any of such Affiliate's
Subsidiaries, and (g) that portion of any Indebtedness of the Company which at
the time of issuance is issued in violation of the Indenture (but, as to any
such Indebtedness, no such violation shall be deemed to exist for purposes of
this clause (g) if the holder(s) of such Indebtedness or their representative or
the Company shall have furnished to the Trustee an opinion of counsel
unqualified in all material respects of independent legal counsel, addressed to
the Trustee (which legal counsel may, as to matters of fact, rely upon a
certificate of the Company) to the effect that the incurrence of such
Indebtedness does not violate the provisions of such Indenture); provided that
the foregoing exclusions shall not affect the priorities of any Indebtedness
arising solely by operation of law in any case or proceeding or similar event
described in clause (a), (b) or (c) of the second paragraph of
"--Subordination."
"Senior Notes" means the 13 1/2% Senior Notes due 2004 of the Company
issued pursuant to the Indenture, dated as of December 1, 1994, between the
Company, as issuer, FRI Louisiana, as subsidiary guarantor, and Shawmut Bank
Connecticut, National Association (now known as Fleet National Bank), as
trustee.
"Senior Note Obligations" means all monetary obligations of every nature of
the Company or a Restricted Subsidiary, including without limitation,
obligations to pay principal and interest, fees, expenses and indemnities, from
time to time owed to the holders or the trustee in respect of the Senior Notes.
"Senior Subordinated Note Obligations" means any principal of, premium, if
any, and interest on, and any other amounts (including, without limitation, any
payment obligations with respect to the Notes as a result of any Asset Sale,
Change of Control or redemption) owing in respect of, the Notes payable pursuant
to the terms of the Notes or the Indenture or upon acceleration of the Notes.
"Stated Maturity" means, when used with respect to any Note or any
installment of interest thereon, the date specified in such Note as the fixed
date on which the principal of such Note or such installment of interest is due
and payable, and, when used with respect to any other Indebtedness or any
installment of interest thereon, means the date specified in the instrument
evidencing or governing such Indebtedness as the fixed date on which the
principal of such Indebtedness or such installment of interest is due and
payable.
"Subordinated Indebtedness" means Indebtedness of the Company which is
expressly subordinated in right of payment to the Notes.
"Subsidiary" means, with respect to any Person, (i) a corporation a
majority of whose Voting Stock is at the time, directly or indirectly, owned by
such Person, by one or more Subsidiaries of such Person or by such Person and
one or more Subsidiaries thereof or (ii) any other Person (other than a
corporation), including, without limitation, a joint venture, in which such
Person, one or more Subsidiaries thereof or such Person and one or more
Subsidiaries thereof, directly or indirectly, at the date of determination
thereof, has at least majority ownership interest entitled to vote in the
election of directors, managers or trustees thereof (or other Person performing
similar functions).
"Subsidiary Guarantee" means any guarantee of the Notes by (i) any
Subsidiary Guarantor in accordance with the provisions set forth in "Subsidiary
Guarantees of Notes" and (ii) any Restricted Subsidiary in accordance with the
provisions set forth in the "Limitation on Guarantees of Indebtedness by
Restricted Subsidiaries" covenant.
"Subsidiary Guarantor" means (i) FRI Louisiana, (ii) each of the Company's
Restricted Subsidiaries that becomes a guarantor of the Notes in compliance with
the provisions described under " -- Subsidiary
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Guarantees of the Notes" or the provisions of the "Limitation on Guarantees of
Indebtedness by Restricted Subsidiaries" covenant and (iii) each of the
Company's Subsidiaries executing a supplemental indenture in which such
Subsidiary agrees to be bound by the terms of the Indenture and to guarantee on
an unsubordinated basis the payment of the Notes pursuant to the provisions
described under "--Subsidiary Guarantees of Notes."
"Unrestricted Subsidiary" means (i) any Subsidiary of the Company that at
the time of determination will be designated an Unrestricted Subsidiary by the
Board of Directors of the Company as provided below and (ii) any Subsidiary of
an Unrestricted Subsidiary. The Board of Directors of the Company may designate
any Subsidiary of the Company as an Unrestricted Subsidiary so long as (a)
neither the Company nor any Restricted Subsidiary is directly or indirectly
liable pursuant to the terms of any Indebtedness of such Subsidiary; (b) no
default with respect to any Indebtedness of such Subsidiary would permit (upon
notice, lapse of time or otherwise) any holder of any other Indebtedness of the
Company or any Restricted Subsidiary to declare a default on such other
Indebtedness or cause the payment thereof to be accelerated or payable prior to
its stated maturity-, (c) neither the Company nor any Restricted Subsidiary has
made an Investment in such Subsidiary unless such Investment was made pursuant
to, and in accordance with, the "Limitation on Restricted Payments" covenant
(other than Investments of the type described in clause (iv) of the definition
of Permitted Investments); and (d) such designation shall not result in the
creation or imposition of any Lien on any of the Properties of the Company or
any Restricted Subsidiary (other than any Permitted Lien or any Lien the
creation or imposition of which shall have been in compliance with the
"Limitation on Liens" covenant); provided, however, that with respect to clause
(a), the Company or a Restricted Subsidiary may be liable for Indebtedness of an
Unrestricted Subsidiary if (x) such liability constituted a Permitted Investment
or a Restricted Payment permitted by the "Limitation on Restricted Payments"
covenant, in each case at the time of incurrence, or (y) the liability would be
a Permitted Investment at the time of designation of such Subsidiary as an
Unrestricted Subsidiary. Any such designation by the Board of Directors of the
Company shall be evidenced to the Trustee by filing a board resolution with the
Trustee giving effect to such designation. The Board of Directors of the Company
may designate any Unrestricted Subsidiary as a Restricted Subsidiary if,
immediately after giving effect to such designation, (i) no Default or Event of
Default shall have occurred and be continuing, (ii) the Company could incur
$1.00 of additional Indebtedness (not including the incurrence of Permitted
Indebtedness) under the first paragraph of the "Limitation on Indebtedness"
covenant and (iii) if any of the Properties of the Company or any of its
Restricted Subsidiaries would upon such designation become subject to any Lien
(other than a Permitted Lien), the creation or imposition of such Lien shall
have been in compliance with the "Limitation on Liens" covenant.
"Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" means any class or classes of Capital Stock pursuant to
which the holders thereof have the general voting power under ordinary
circumstances to elect at least a majority of the board of directors, managers
or trustees of any Person (irrespective of whether or not, at the time, stock of
any other class or classes shall have, or might have, voting power by reason of
the happening of any contingency).
"Wholly Owned Restricted Subsidiary" means any Restricted Subsidiary to the
extent all of the Capital Stock or other ownership interests in such Restricted
Subsidiary, other than any directors qualifying shares mandated by applicable
law, is owned directly or indirectly by the Company.
BOOK-ENTRY DELIVERY AND FORM
The Notes will be issued in the form of a fully registered Global
Certificate. The Global Certificate will be deposited with, or on behalf of, The
Depository Trust Company, New York, New York (the "Depositary") and registered
in the name of the Depositary's nominee.
Except as set forth below, the Global Certificate may be transferred, in
whole and not in part, only to another nominee of the Depositary or to a
successor of the Depositary or its nominee.
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<PAGE> 93
The Depositary has advised the Company and the Underwriters as follows: It
is a limited-purpose trust company which was created to hold securities for its
participating organizations (the "Participants") and to facilitate the clearance
and settlement of transactions in such securities between Participants through
electronic book-entry changes in accounts of its Participants. Participants
include securities brokers and dealers (including the Underwriters), banks,
trust companies, clearing corporations and certain other organizations. Access
to the Depositary's book-entry system is also available to others, such as
banks, brokers, dealers and trust companies that clear through or maintain a
custodial relationship with a Participant, either directly or indirectly
("indirect participants"). Persons who are not Participants may beneficially own
securities held by the Depositary only through Participants or indirect
participants.
The Depositary has also advised that pursuant to procedures established by
it (i) upon the issuance by the Company of the Notes, the Depositary will credit
the accounts of Participants designated by the Underwriters with the principal
amount of the Notes purchased by the Underwriters, and (ii) ownership of
beneficial interests in the Global Certificate will be shown on, and the
transfer of that ownership will be effected only through, records maintained by
the Depositary (with respect to Participants' interests), the Participants and
the indirect participants. The laws of some states require that certain persons
take physical delivery in definitive form of securities which they own.
Consequently, the ability to transfer beneficial interests in the Global
Certificate is limited to such extent.
So long as a nominee of the Depositary is the registered owner of the
Global Certificate, such nominee will be considered the sole owner or holder of
the Notes for all purposes under the Indenture. Except as provided below, owners
of beneficial interests in the Global Certificate will not be entitled to have
Notes registered in their names, will not receive or be entitled to receive
physical delivery of Notes in definitive form and will not be considered the
owners or holders thereof under the Indenture.
Neither the Company, the Trustee, the paying agent nor the Notes registrar
will have any responsibility or liability for any aspect of the records relating
to or payments made on account of beneficial ownership interests in the Global
Certificate, or for maintaining, supervising or reviewing any records relating
to such beneficial ownership interests.
Principal and interest payments on the Global Certificate registered in the
name of the Depositary's nominee will be made by the Company through the paying
agent to the Depositary's nominee as the registered owner of the Global
Certificate. Under the terms of the Indenture, the Company and the Trustee will
treat the persons in whose names the Notes are registered as the owners of such
Notes for the purpose of receiving payments of principal and interest on such
Notes and for all other purposes whatsoever. Therefore, neither the Company, the
Trustee nor the paying agent has any direct responsibility or liability for the
payment of principal or interest on the Notes to owners of beneficial interests
in the Global Certificate. The Depositary has advised the Company and the
Trustee that its present practice is, upon receipt of any payment of principal
or interest to credit immediately the accounts of the Participants with payment
in amounts proportionate to their respective holdings in principal amount of
beneficial interests in the Global Certificate as shown on the records of the
Depositary. Payments by Participants and indirect participants to owners of
beneficial interests in the Global Certificate will be governed by standing
instructions and customary practices, as is now the case with securities held
for the accounts of customers in bearer form or registered in "street name" and
will be the responsibility of such Participants or indirect participants.
As long as the Notes are represented by a Global Certificate, the
Depositary's nominee will be the holder of the Notes and therefore will be the
only entity that can exercise a right to repayment or repurchase of the Notes.
See "Certain Covenants -- Change of Control" and "--Limitation on Disposition of
Proceeds of Asset Sales." Notice by Participants or indirect participants or by
owners of beneficial interests in a Global Certificate held through such
Participants or indirect participants of the exercise of the option to elect
repayment of beneficial interests in Notes represented by a Global Certificate
must be transmitted to the Depositary in accordance with its procedures on a
form required by the Depositary and provided to Participants. In order to ensure
that the Depositary's nominee will timely exercise a right to repayment with
respect to a particular Note, the beneficial owner of such Note must instruct
the broker or other Participant or indirect participant through which it holds
an interest in such Note to notify the Note of its desire to exercise a
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<PAGE> 94
right to repayment. Different firms have different cut-off times for accepting
instructions from their customers and, accordingly, each beneficial owner should
consult the broker or other Participant or indirect participant through which it
holds an interest in a Note in order to ascertain the cut-off time by which such
an instruction must be given in order for timely notice to be delivered to the
Depositary. The Company will not be liable for any delay in delivery to the
Paying Agent of notices of the exercise of the option to elect repayment.
The Company will issue Notes in definitive form in exchange for the Global
Certificate if, and only if, either (1) the Depositary is at any time unwilling
or unable to continue as depositary and a successor depositary is not appointed
by the Company within 90 days, (2) an Event of Default has occurred and is
continuing and the Notes registrar has received a request from the Depositary to
issue Notes in definitive form in lieu of all or a portion of the Global
Certificate (in which case the Company shall deliver Notes in definitive form
within 30 days of such request), or (3) the Company determines not to have the
Notes represented by a Global Certificate. In either instance, an owner of a
beneficial interest in the Global Certificate will be entitled to have Notes
equal in principal amount to such beneficial interest registered in its name and
will be entitled to physical delivery of such Notes in definitive form. Notes so
issued in definitive form will be issued in denominations of $1,000 and integral
multiples thereof and will be issued in registered form only, without coupons.
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<PAGE> 95
UNDERWRITING
Subject to the terms and conditions set forth in the Purchase Agreement
(the "Purchase Agreement") among the Company, Merrill Lynch, Pierce, Fenner &
Smith Incorporated, Bear, Stearns & Co. Inc. and Salomon Brothers Inc (the
"Underwriters"), the Company has agreed to sell to each of the Underwriters, and
each of the Underwriters has severally agreed to purchase, the principal amount
of Notes set forth below opposite their respective names below. The Purchase
Agreement provides that the obligations of the Underwriters are subject to
certain conditions precedent and that the Underwriters are committed to purchase
all of the Notes if any are purchased.
<TABLE>
<CAPTION>
PRINCIPAL
UNDERWRITER AMOUNT
- ------------------------------------------------------------------------------ -----------
<S> <C>
Merrill Lynch, Pierce, Fenner & Smith
Incorporated..................................................... $112,000,000
Bear, Stearns & Co. Inc...................................................... 24,000,000
Salomon Brothers Inc......................................................... 24,000,000
------------
Total........................................................... $160,000,000
============
</TABLE>
The Underwriters have advised the Company that the Underwriters propose
initially to offer the Notes to the public at the public offering price set
forth on the cover page of this Prospectus, and to certain dealers at such price
less a concession not in excess of .25% of the principal amount of the Notes.
The Underwriters may allow, and such dealers may reallow, a discount not in
excess of .125% of the principal amount of the Notes to certain other dealers.
After the initial public offering, the public offering price, concession and
discount may be changed.
The Notes are a new issue of securities for which there is currently no
public market. The Company does not intend to apply for listing of the Notes on
any securities exchange. The Company has been advised by the Underwriters that
subject to the applicable laws and regulations, the Underwriters presently
intend to make a market in the Notes, although the Underwriters are under no
obligation to do so and may discontinue any market-making activities with
respect to the Notes at any time without notice. No assurance, however, can be
given as to the liquidity of the trading market for the Notes or that an active
trading market for the Notes will develop. If an active public market does not
develop, the market price and liquidity of the Notes may be adversely affected.
The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act, or to contribute to
payments the Underwriters may be required to make in respect thereof.
LEGAL MATTERS
Certain legal matters in connection with the securities being offered
hereby will be passed upon for the Company by Andrews & Kurth L.L.P., Houston,
Texas and for the Underwriters by Baker & Botts, L.L.P., Dallas, Texas.
EXPERTS
The consolidated financial statements of the Company included and
incorporated by reference in this Prospectus have been audited by Arthur
Andersen LLP, independent public accountants, as indicated in their reports with
respect thereto, and are included or incorporated herein in reliance upon the
authority of said firm as experts in giving said reports.
Information relating to the estimated proved reserves of oil and gas and
the related estimates of future net cash flows and present values of future net
revenues thereof at December 31, 1993, 1994 and 1995 included or incorporated
herein and in the notes to the financial statements of the Company have been
prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers, and are included herein and
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<PAGE> 96
incorporated by reference herein in reliance upon the authority of such firm as
an expert in petroleum engineering.
The statements of combined oil and gas revenues and direct operating
expenses of certain oil and gas producing properties to be acquired from Mobil
Oil Exploration & Producing Southeast Inc. for each of the three years in the
period ended December 31, 1995, appearing in this Prospectus and Registration
Statement have been audited by Ernst & Young LLP, independent auditors, as set
forth in their report thereon appearing elsewhere herein, and are included in
reliance upon such report given upon the authority of such firm as experts in
accounting and auditing.
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Exchange
Act and in accordance therewith files reports, proxy statements and other
information with the Commission. Such reports, proxy statements, and other
information filed by the Company can be inspected and copied at the public
reference facilities of the Commission, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington. D.C. 20549, as well as the following Regional Offices: 7 World Trade
Center, New York, New York 10048; and Northwestern Atrium Center, 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661-2511 or may be obtained on
the Internet at http://www.sec.gov. Copies can be obtained by mail at prescribed
rates. Requests for copies should be directed to the Commission's Public
Reference Section, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C.
20549. The Company's Common Stock is traded on the New York Stock Exchange and,
as a result, the periodic reports, proxy statements and other information filed
by the Company with the Commission can be inspected at the offices of the New
York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.
The Company has filed with the Commission a Registration Statement on Form
S-3 ("Registration Statement") under the Securities Act with respect to the
Notes offered by this Prospectus. This Prospectus does not contain all the
information set forth in the Registration Statement and the exhibits thereto.
For further information with respect to the Company and the Notes being offered
hereby, reference is made to the Registration Statement and the exhibits
thereto. Although the Company believes that all the material terms of the
Company's material contracts and agreements have been summarized in the
Prospectus, statements contained in this Prospectus concerning the provisions of
documents filed with the Registration Statement as exhibits are necessarily
summaries of such documents, and each such statement is qualified in its
entirety by reference to the copy of the applicable document filed with the
Commission. All these documents may be inspected without charge at the offices
of the Commission, the addresses of which are set forth above, and copies may be
obtained therefrom at prescribed rates.
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<PAGE> 97
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The following documents heretofore filed by the Company with the Commission
pursuant to the Exchange Act are incorporated herein by reference:
a. The Company's Annual Report on Form 10-K for the year ended
December 31, 1995;
b. The Company's Quarterly Reports on Form 10-Q for the quarters ended
March 31, 1996 and June 30, 1996; and
c. The description of the Company's Common Stock contained in the
Company's Registration Statement on Form 8-A filed March 8, 1996.
All documents filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to
the termination of the offering made hereby shall be deemed to be incorporated
by reference into this Prospectus and to be a part hereof from the date of
filing of such documents. Any statement contained in a document incorporated or
deemed to be incorporated by reference herein shall be deemed to be modified or
superseded for purposes of this Prospectus to the extent that a statement
contained herein or in any other subsequently filed document which also is or is
deemed to be incorporated by reference herein modifies or supersedes such
statement. Any such statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of this Prospectus.
ANY PERSON RECEIVING A COPY OF THIS PROSPECTUS MAY OBTAIN WITHOUT CHARGE,
UPON WRITTEN OR ORAL REQUEST, A COPY OF ANY OF THE DOCUMENTS INCORPORATED BY
REFERENCE HEREIN, EXCEPT FOR THE EXHIBITS TO SUCH DOCUMENTS (UNLESS SUCH
EXHIBITS ARE SPECIFICALLY INCORPORATED BY REFERENCE INTO SUCH DOCUMENTS).
REQUESTS SHOULD BE ADDRESSED TO INVESTOR RELATIONS, FLORES & RUCKS, INC., 8440
JEFFERSON HIGHWAY, SUITE 420, BATON ROUGE, LOUISIANA 70809, (504) 927-1450.
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GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry and this Prospectus. Unless otherwise indicated in this
Prospectus, natural gas volumes are stated at the legal pressure base of the
state or area in which the reserves are located and at 60() Fahrenheit. BOEs are
determined using the ratio of six Mcf of natural gas to one Bbl of oil.
"Bbl" means a barrel of 42 U.S. gallons of oil.
"Bcf" means billion cubic feet of natural gas.
"BCFGE" means billion cubic feet of natural gas equivalent.
"BOE" means barrels of oil equivalent.
"BOPD" means barrels of oil per day.
"Btu" or "British Thermal Unit" means the quantity of heat required to
raise the temperature of one pound of water by one degree Fahrenheit.
"BBtu" means one billion British Thermal Units.
"Completion" means the installation of permanent equipment for the
production of oil or gas.
"Condensate" means a hydrocarbon mixture that becomes liquid and separates
from natural gas when the gas is produced and is similar to crude oil.
"Development well" means a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
"Gross,"when used with respect to acres or wells, refers to the total acres
or wells in which the Company has a working interest.
"MBbls" means thousands of barrels of oil.
"Mcf" means thousand cubic feet of natural gas.
"MCFPD" means thousand cubic feet of natural gas per day.
"MMBbls" means millions of barrels of oil.
"MMBOE" means million barrels of oil equivalent.
"MMBtu" means one million British Thermal Units.
"MMcf" means million cubic feet of natural gas.
"Net" when used with respect to acres or wells, refers to gross acres of
wells multiplied, in each case, by the percentage working interest owned by the
Company.
"Net production" means production that is owned by the Company less
royalties and production due others.
"Oil" means crude oil or condensate.
"Operator" means the individual or company responsible for the exploration,
development, and production of an oil or gas well or lease.
"Present Value of Future Net Revenues" or "Present Value of Proved
Reserves" means the present value of estimated future revenues to be generated
from the production of proved reserves calculated in accordance with Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation, without
giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expense and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
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"Project" means a proposal to add a producing completion of oil or gas. A
proposal may vary in range from work authorized to be performed to proposals
that are founded in geologic and engineering principles yet require further
research before funds are authorized.
"Proved developed reserves" means reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
"Proved reserves" means the estimated quantities of crude oil, natural gas,
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
i. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
ii. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
iii. Estimates of proved reserves do not include the following: (A)
oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (C) crude oil, natural gas, and natural gas liquids that
may occur in undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids that may be recovered from oil shales, coal, gilsonite
and other such sources.
"Proved undeveloped reserves" means reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
"Recompletion" means the completion for production of an existing well bore
in another formation from that in which the well has been previously completed.
"Reserves" means proved reserves.
"Royalty" means an interest in an oil and gas lease that gives the owner of
the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
"Spud" means to start drilling a new well (or restart).
99
<PAGE> 100
"3-D seismic" means seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
"Waterflood" means the injection of water into a reservoir to fill pores
vacated by produced fluids, thus maintaining reservoir pressure and assisting
production.
"Working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties. For example, the owner of a 100% working
interest in a lease burdened only by a landowner's royalty of 12.5% would be
required to pay 100% of the costs of a well but would be entitled to retain
87.5% of the production.
"Workover" means operations on a producing well to restore or increase
production.
100
<PAGE> 101
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Consolidated Financial Statements of Flores & Rucks, Inc.
Report of Independent Public Accountants........................................... F-2
Consolidated Balance Sheets as of December 31, 1995 and 1994....................... F-3
Consolidated Statements of Operations for the years ended December 31, 1995, 1994
and 1993........................................................................ F-4
Consolidated Statements of Stockholders' Equity for the years ended December 31,
1995, 1994 and 1993............................................................. F-5
Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994
and 1993........................................................................ F-6
Notes to Consolidated Financial Statements......................................... F-7
Consolidated Balance Sheet as of June 30, 1996..................................... F-23
Consolidated Statements of Operations for the six months ended June 30, 1996 and
1995............................................................................ F-24
Consolidated Statements of Cash Flows for the six months ended June 30, 1996 and
1995............................................................................ F-25
Notes to Consolidated Financial Statements......................................... F-26
Financial Statements of Mobil Properties
Report of Independent Auditors..................................................... F-27
Statements of Combined Oil and Gas Revenues and Direct Operating Expenses.......... F-28
Notes to Statements of Combined Oil and Gas Revenues and Direct Operating
Expenses........................................................................ F-29
</TABLE>
F-1
<PAGE> 102
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Flores & Rucks, Inc. and subsidiaries:
We have audited the accompanying consolidated balance sheets of Flores &
Rucks, Inc. (a Delaware corporation) and subsidiaries, as of December 31, 1995
and 1994 and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1995. 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 in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Flores & Rucks, Inc. and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
February 16, 1996
F-2
<PAGE> 103
FLORES & RUCKS, INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1995 1994
------------ -----------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................................... $ 212,238 $ 568,690
Joint interest receivables................................... 390,275 300,580
Oil and gas sales receivables................................ 17,546,127 10,308,998
Accounts receivable -- stockholders.......................... 129,129 125,377
Prepaid expenses............................................. 390,412 516,518
Other current assets......................................... 424,824 72,718
------------ ------------
Total current assets................................. 19,093,005 11,892,881
Oil and gas properties -- full cost method:
Evaluated.................................................... 275,581,044 206,537,120
Less accumulated depreciation, depletion, and amortization... (114,040,044) (60,019,583)
------------ ------------
161,541,000 146,517,537
Unevaluated properties excluded from amortization............ 19,041,148 14,432,594
Other assets:
Furniture and equipment, less accumulated depreciation of
$1,258,225 and $527,257 in 1995 and 1994, respectively.... 2,340,641 983,718
Restricted deposits.......................................... 4,259,182 2,300,298
Deferred financing costs..................................... 5,127,974 5,579,161
Notes receivable............................................. -- 275,524
Deferred tax asset........................................... 4,692,263 --
------------ ------------
Total assets......................................... $216,095,213 $181,981,713
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities..................... $ 15,090,791 $13,133,447
Oil and gas sales payable.................................... 5,177,277 2,694,239
Accrued interest............................................. 2,651,097 1,106,176
------------ ------------
Total current liabilities............................ 22,919,165 16,933,862
Long-term debt................................................. 157,391,556 144,039,269
Notes payable to be refinanced under revolving line of
credit....................................................... 14,300,000 10,000,000
Other noncurrent liabilities................................... 638,609 638,609
Deferred hedge revenue......................................... 870,333 666,667
Stockholders' equity:
Preferred stock, $.01 par value; authorized 10,000,000
shares, no shares issued or outstanding at December 31,
1995...................................................... -- --
Common stock, $.01 par value; authorized 100,000,000 shares;
issued and outstanding 15,044,125 shares and 15,000,000
shares at December 31, 1995 and 1994, respectively........ 150,441 150,000
Paid-in capital.............................................. 27,638,465 27,268,957
Retained earnings (deficit).................................. (7,813,356) (17,715,651)
------------ ------------
Total stockholders' equity........................... 19,975,550 9,703,306
------------ ------------
Total liabilities and stockholders' equity........... $216,095,213 $181,981,713
============ ============
</TABLE>
The accompanying notes to financial statements are an integral part of these
statements.
F-3
<PAGE> 104
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
----------- ----------- ----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales................................. $127,406,084 $ 75,462,644 $ 47,355,579
Plant processing income (loss).................... 564,042 (67,532) 127,031
------------ ------------ ------------
Total revenues............................ 127,970,126 75,395,112 47,482,610
Operating expenses:
Lease operations.................................. 30,023,426 23,577,089 14,203,765
Severance taxes................................... 10,023,104 6,746,928 4,997,533
Depreciation, depletion and amortization.......... 54,083,782 36,459,029 20,140,253
------------ ------------ ------------
Total operating expenses.................. 94,130,312 66,783,046 39,341,551
General and administrative expenses................. 11,312,153 10,350,572 5,031,674
Interest expense.................................... 17,620,226 4,507,307 1,055,198
Interest income and other........................... (302,597) (748,479) (172,695)
Loss on production payment repurchase and
refinancing....................................... -- 16,681,211 --
------------ ------------ ------------
Net income (loss) before income taxes............... 5,210,032 (22,178,545) 2,226,882
Income tax benefit.................................. 4,692,263 -- --
------------ ------------ ------------
Net income (loss)................................... $ 9,902,295 $(22,178,545) $ 2,226,882
============ ============ ============
Weighted average common shares outstanding.......... 15,043,122 N.M. N.M.
Earnings per common share........................... $.66 N.M. N.M.
</TABLE>
The accompanying notes to financial statements are an integral part of these
statements.
F-4
<PAGE> 105
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
RETAINED
COMMON PAID-IN EARNINGS
STOCK CAPITAL (DEFICIT) TOTAL
-------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Balance at December 31, 1992............ $ 1,000 $ -- $ 347,816 $ 348,816
Net income............................ -- -- 2,226,882 2,226,882
Distributions......................... -- -- (3,400,400) (3,400,400)
-------- ----------- ------------ ------------
Balance at December 31, 1993............ 1,000 -- (825,702) (824,702)
Sale of stock......................... 149,000 52,657,553 -- 52,806,553
Repurchase of common stock............ -- (18,700,000) -- (18,700,000)
Net loss.............................. -- -- (22,178,545) (22,178,545)
Distributions......................... -- -- (1,400,000) (1,400,000)
Reclassification of accumulated
deficit at date of conversion to a
subchapter C corporation........... -- (6,688,596) 6,688,596 --
-------- ------------ ------------ ------------
Balance at December 31, 1994............ $150,000 $27,268,957 $(17,715,651) $ 9,703,306
Sale of stock......................... 441 369,508 -- 369,949
Net income............................ -- -- 9,902,295 9,902,295
-------- ------------ ------------ ------------
Balance at December 31, 1995............ $150,441 $27,638,465 $ (7,813,356) $ 19,975,550
======== =========== ============ ============
</TABLE>
The accompanying notes to financial statements are an integral part of these
statements.
F-5
<PAGE> 106
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1995 1994 1993
------------ ------------- -------------
<S> <C> <C> <C>
Operating activities:
Net income (loss)............................ $ 9,902,295 $ (22,178,545) $ 2,226,882
Adjustments to reconcile net income (loss) to
net cash provided by (used in) operating
activities:
Depreciation, depletion and
amortization............................ 54,751,429 36,845,015 20,271,237
Deferred hedge revenue.................... 203,666 (565,180) 1,147,125
Recognition of deferred revenue on sale of
production payment interest............. -- (23,857,212) (18,294,127)
Deferred tax benefit...................... (4,692,263) -- --
Sale of production payment interests......... -- -- 95,678,000
Prepayment of production payment interests... -- -- (947,484)
Repurchase of production payment interests... -- (107,951,703) --
Changes in operating assets and liabilities:
Accrued interest.......................... 1,555,132 1,947,489 448,475
Receivables............................... (7,055,051) (6,208,990) (2,461,224)
Prepaid expenses.......................... 126,106 -- 175,200
Other current assets...................... (352,106) (139,976) (50,008)
Accounts payable and accrued
liabilities............................. 1,957,344 5,155,926 4,635,564
Oil and gas sales payable................. 2,483,037 1,468,107 282,216
------------ ------------- -------------
Net cash provided by (used in)
operating activities............... 58,879,589 (115,485,069) 103,111,856
------------ ------------- -------------
Investing activities:
Additions to oil and gas properties and
furniture and equipment................... (75,740,369) (39,408,546) (113,113,620)
(Increase) decrease in restricted deposits... (1,958,884) (1,221,377) 288,356
Proceeds from sale of oil and gas
properties................................ -- -- 12,084,737
Purchase of minority interest................ -- (5,977,097) --
------------ ------------- -------------
Net cash used in investing
activities......................... (77,699,253) (46,607,020) (100,740,527)
------------ ------------- -------------
Financing activities:
Sale of stock................................ 369,949 52,806,553 --
Borrowings on notes payable.................. 99,000,020 181,014,776 --
Payments of notes payable.................... (81,357,944) (55,632,361) --
Deferred financing costs..................... 451,187 (5,626,787) --
Repurchase of common stock................... -- (8,700,000) --
Distributions to stockholders................ -- (1,400,000) (2,400,400)
------------ ------------- -------------
Net cash provided by (used in)
financing activities............... 18,463,212 162,462,181 (2,400,400)
------------ ------------- -------------
Increase (decrease) in cash and cash
equivalents.................................. (356,452) 370,092 (29,071)
Cash and cash equivalents, beginning of the
period....................................... 568,690 198,598 227,669
------------ ------------- -------------
Cash and cash equivalents, end of the period... $ 212,238 $ 568,690 $ 198,598
============ ============= =============
Interest paid during the period................ $ 18,288,156 $ 2,808,721 $ 606,723
============ ============= =============
</TABLE>
The accompanying notes to financial statements are an integral part of these
statements.
F-6
<PAGE> 107
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
Flores & Rucks, Inc., a Delaware corporation (the "Company"), is an
independent energy company engaged in the exploration, development, acquisition
and production of crude oil and natural gas, with operations primarily in the
shallow offshore regions of Louisiana. The Company was formed on September 22,
1994, to succeed to the business of Flores & Rucks, Inc., a Louisiana
corporation ("FRI Louisiana") and Flores & Rucks LLC (the "LLC"). Concurrent
with the closing of the Initial Offerings (See Note 2) on December 7, 1994, FRI
Louisiana was merged into a wholly owned subsidiary of the Company. Because the
transaction represented the reorganization of entities under common control, the
merger was treated in a manner similar to a pooling of interests.
Hereinafter, the "Company" refers to Flores & Rucks, Inc., a Delaware
corporation, its predecessors and their respective subsidiaries.
Effective January 1, 1993, FRI Louisiana issued 2,000 shares of common
stock to the two stockholders of an entity which held the rights under an
operating agreement to operate substantially all of FRI Louisiana's oil and gas
properties. These two stockholders were deemed co-promoters of FRI Louisiana
upon the exchange. As no tangible assets, or any assets with predecessor basis,
were acquired by FRI Louisiana in connection with the exchange, no value was
attributed to the stock issued. These shares were subsequently reacquired (See
Note 7).
On December 28, 1993, FRI Louisiana transferred its interests in
substantially all of its oil and gas properties to the LLC in return for an
87.5% ownership interest. The remaining 12.5% interest (the "Minority Interest")
was owned by an unrelated party, Franks Petroleum, Inc. ("Franks"). FRI
Louisiana proportionately consolidated its interest in LLC.
The Company is substantially leveraged. As such, a significant portion of
the Company's cash flow from operations will be dedicated to debt service. As
with other independent oil and gas producers, the Company is subject to numerous
uncertainties and commitments associated with its operations. For example, the
Company's results of operations are highly dependent upon the prices received
for oil and gas. In addition, the Company will be required to make substantial
future capital expenditures for the acquisition, exploration, development,
production and abandonment of its oil and gas properties.
Subsidiary Guaranty
All of the Company's operating income and cash flow is generated by FRI
Louisiana, a wholly owned subsidiary and the Subsidiary Guarantor of the
Company. The separate financial statements of FRI Louisiana are not included
herein because (i) FRI Louisiana is the only direct operating subsidiary of the
Company; (ii) FRI Louisiana has fully and unconditionally guaranteed the Senior
Notes (as defined in Note 2); (iii) the aggregate assets, liabilities, earnings,
and equity of FRI Louisiana are substantially equivalent to the assets,
liabilities, earnings and equity of the Company on a consolidated basis; and
(iv) the separate financial statements and other disclosures concerning FRI
Louisiana are not deemed material.
Use of 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 and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
F-7
<PAGE> 108
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Oil and Gas Properties
The Company's exploration and production activities are accounted for under
the full cost method. Under this method, all acquisition, exploration and
development costs, including certain related employee costs, incurred for the
purpose of finding oil and gas are capitalized. Such amounts include the cost of
drilling and equipping productive wells, dry hole costs, lease acquisition
costs, delay rentals, and costs related to such activities. Employee costs
associated with production operations and general corporate activities are
expensed in the period incurred. The Company capitalized $1,643,000 and $535,000
of employee related costs directly associated with the acquisition, development
or exploration of oil and gas properties during the years ended December 31,
1995 and 1994, respectively. No such costs were capitalized by the Company
during the year ended December 31, 1993. The Company's proportionate interests
in properties held through LLC (as of December 31, 1993) or under joint venture,
partnership or similar arrangements are included in oil and gas properties.
Transactions involving sales of reserves in place, unless unusually significant,
are recorded as adjustments to oil and gas properties. Capitalized costs are
limited to the sum of the present value of future net revenues discounted at 10%
related to estimated production of proved reserves (which includes deferred
hedge revenue) and the lower of cost or estimated fair value of unevaluated
properties.
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 oil and gas properties, including an
estimate of future development, restoration, dismantlement and abandonment costs
of proved properties, are included in the computation base, with the exception
of certain costs associated with unevaluated oil and gas properties. The oil and
gas reserves are estimated periodically by independent petroleum engineers. The
Company evaluates all unevaluated oil and gas properties on a quarterly basis to
determine if any impairment has occurred. Any impairment to unevaluated
properties will be 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.
In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121 (SFAS 121) regarding
accounting for the impairment of long-lived assets. The Company is required to
adopt SFAS 121 in 1996. The effect of adopting SFAS 121 will not be material.
Furniture and Equipment
Depreciation is computed using the straight-line method over the estimated
useful lives of the assets.
Oil and Gas Revenue
The Company records oil and gas revenue on the sales method. As a result of
this policy, the Company did not record revenues of $20,000 for the year ended
December 31, 1995, on gas volumes that the Company was entitled to, but which
were sold by a joint owner in order to reduce previous gas imbalances. The
Company recorded revenue of $376,000 and $519,000 during the years ended
December 31, 1994 and 1993, respectively, on gas volumes sold in excess of its
entitled share of production. In addition, in connection with an oil and gas
property acquisition, the Company assumed a liability for overdelivered gas of
556,994 Mcf, which has been recorded as a long-term liability of $638,609. As of
December 31, 1995, the Company is in a net overdelivered position of 1,080,726
Mcf, of which the first 523,732 Mcf will reduce future oil and gas revenue as
the underdelivered parties recoup their share of production.
The Company records as oil and gas revenue the payments received from (or
made to) a third party under contracts to hedge future oil and gas production
(See Note 13).
F-8
<PAGE> 109
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Statements of Cash Flows
The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents.
Earnings Per Common Share
For the year ended December 31, 1995, earnings per common share are based
on the weighted average number of shares of common stock outstanding for the
period. The Company had 1,495,500 stock options outstanding as of December 31,
1995. The options were not reflected as common stock equivalents for the 1995
period as the dilutive effect caused by the options on earnings per share was
less than 3%.
Earnings per common share has not been presented for the Company for the
years ended December 31, 1994 and 1993, as these amounts would not be meaningful
or indicative of the ongoing entity due to the Initial Offerings (See Note 2)
and related transactions.
Deferred Financing Costs
The Company has $5,127,974, net of accumulated amortization of $659,728,
recorded as deferred financing costs as of December 31, 1995, which is related
to the senior revolving bank credit facility (the "Revolving Credit Facility")
and the sale of the Senior Notes (See Note 2). In conjunction with the Initial
Offerings (See Note 2), a balance of $1,007,114, which represented deferred
financing costs associated with the term and development loans, discussed in
Note 9, was expensed in the fourth quarter of 1994. Deferred financing costs are
being amortized on a straight-line basis over the life of the related loans.
Fair Value of Financial Instruments
Fair value of cash, cash equivalents, accounts receivable and accounts
payable approximates book value at December 31, 1995. Fair value of debt is
determined based upon market value, if traded, or discounted at the estimated
rate the Company would incur currently on similar debt.
Reclassifications
Certain reclassifications have been made to conform financial statement
presentation between periods.
2. INITIAL PUBLIC OFFERINGS
On December 7, 1994, the Company closed initial public offerings (the
"Initial Offerings") issuing 5,750,000 shares of common stock at $10 per share
and $125 million of 13 1/2% Senior Notes due December 1, 2004 (the "Senior
Notes"), and concurrently exchanged the Enron Option (See Note 4) and $1,000 for
one million shares of common stock. Additionally, the Company acquired the
Franks interest (for $6.0 million cash) and LLC was merged into the Company. In
addition, concurrent with the closing of the Initial Offerings, the Company
acquired the production payment obligations for East Bay Complex and Main Pass
69 (See Notes 3 and 4), repaid the term loan and development loans (See Note 9)
and paid off notes to current and former stockholders (See Note 7).
In January 1995, the Company issued an additional 40,000 shares of common
stock relating to the exercise of the underwriters over-allotment option. Net
proceeds to the Company from the issuance of these shares was $372,000.
3. INVESTMENT IN OIL AND GAS PROPERTIES
On June 11, 1992, the Company acquired a producing oil and gas property
("Main Pass 69") from Shell Oil Company, its affiliates and subsidiaries
("Shell"), for $39.2 million. On June 10, 1993, the Company
F-9
<PAGE> 110
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
acquired a second producing property (the "East Bay Complex") from Shell for
$131.9 million. Concurrent with these acquisitions, the Company assigned
overriding royalty interests burdening one-eighth of the working interests to a
company owned by a stockholder for services rendered in connection with the
acquisitions. In addition, the Company sold to Franks the one-eighth working
interests subject to the override in return for the assumption of one-eighth of
the volumetric production payment liabilities related thereto (See Note 4) and,
for the East Bay Complex, one-eighth of the note payable to Shell (Note 9). In
addition, see Note 4 for a discussion of the sale of an option to Enron
Financial Corporation related to the East Bay Complex.
On December 7, 1994, the Company acquired Franks' interest in the LLC for
$6 million and recorded the acquisition using the purchase method. Included in
the purchase the Company acquired cash totaling $23,000, other current assets
totaling $56,000, Franks' share of a plug and abandonment escrow totaling
$269,000, and other assets totaling $124,000. In addition, the Company assumed
accrued interest payable of $53,000, a gas balancing liability of $80,000, notes
payable on JEDI (as defined in Note 9) loans of approximately $4.4 million,
deferred hedge revenue of $85,000, an approximate $1.8 million liability owed to
the Company and deferred production payment revenues of approximately $15.5
million, as well as the assumption of a $710,000 liability owed to the LLC. The
Company recorded an increase in the full cost pool of $28.1 million. The Company
allocated the purchase price between evaluated and unevaluated properties based
on estimated relative fair market value.
The following table discloses certain financial data relative to the
Company's oil and gas producing activities, substantially all of which are
located in the offshore waters of the continental United States.
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Costs incurred during period:
Capitalized
Purchase of producing properties...... $ 624,097 $ 25,441,295 $115,490,554
Purchase of unevaluated properties.... 2,381,227 14,736,334 --
Exploration costs..................... 18,106,000 9,829,000 --
Development costs including
capitalized workovers............... 47,829,175 23,083,108 7,052,337
Plugging and abandonment costs........ 236,000 727,370 1,057,194
Capitalized interest on unevaluated
properties and capitalized general
and administrative expenses......... 4,475,979 659,552 --
------------ ------------ ------------
$ 73,652,478 $ 74,476,659 $123,600,085
============ ============ ============
Charged to expense
Operating costs:
Recurring lease operating
expenses......................... $ 28,648,019 $ 22,709,507 $ 13,612,882
Major maintenance expenses.......... 1,375,407 867,582 590,883
------------ ------------ ------------
Total operating costs............ $ 30,023,426 $ 23,577,089 $ 14,203,765
============ ============ ============
Severance taxes..................... $ 10,023,104 $ 6,746,928 $ 4,997,533
============ ============ ============
Oil and gas properties:
Balance, beginning of period............. $220,969,714 $146,493,055 $34,977,707
Additions................................ 73,652,478 74,476,659 123,600,085
Sales.................................... -- -- (12,084,737)
------------ ------------ ------------
Balance, end of period................... $294,622,192 $220,969,714 $146,493,055
============ ============ ============
</TABLE>
F-10
<PAGE> 111
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Accumulated depreciation, depletion and
amortization:
Balance, beginning of period............. $ 60,019,583 $ 23,560,554 $ 3,420,301
Provision for depreciation, depletion and
amortization.......................... 54,020,461 36,459,029 20,140,253
------------ ------------ ------------
Balance, end of period................... 114,040,044 60,019,583 23,560,554
Net capitalized costs............ $180,582,148 $160,950,131 $122,932,501
============ ============ ============
</TABLE>
The following tables discloses financial data associated with capitalized
unevaluated costs as of December 31, 1995.
<TABLE>
<CAPTION>
COSTS INCURRED DURING
THE YEAR ENDED
BALANCE AT DECEMBER 31,
DECEMBER 31, ----------------------
1995 1995 1994
------------ --------- ---------
<S> <C> <C> <C>
Acquisition costs............................... $10,400,558 $1,164,781 $9,235,777
Exploration costs............................... 5,060,227 5,060,227 --
Development costs............................... 1,819,398 1,819,398 --
Capitalized interest............................ 1,760,965 1,682,030 78,935
----------- ---------- ----------
$19,041,148 $9,726,436 $9,314,712
=========== ========== ==========
</TABLE>
4. PRODUCTION PAYMENTS
Concurrent with the Main Pass 69 and East Bay Complex acquisitions, the
Company sold to Enron Reserve Acquisition Corp. ("ERAC") nonrecourse volumetric
production payment interests of approximately $36.7 million and $95.7 million,
respectively, net of the amounts assumed by Franks.
The Company deferred the revenue associated with the sale of these
production payment interests because a substantial obligation for future
performance existed. Under the terms of the sales, the Company was obligated to
deliver the production payment volumes free and clear of lease operating
expenses, production taxes, plugging and abandonment and other capital costs.
The deferred revenue was amortized on the unit-of-production method and
recognized as oil and gas revenues as the associated hydrocarbons were
delivered. In addition, under separate agreements, the Company was required to
sell all excess production over production payment volumes from the subject
properties to an affiliate of ERAC during the same periods. Sales from the East
Bay Complex were made at market prices, whereas sales from Main Pass 69 were
made at the affiliate's posted price, which during the eleven months ended
November 30, 1994 was approximately $1.29 per barrel below other buyers'
postings for similar crude oil. Sales from Main Pass 69 for December 1994 were
made to the affiliate at market prices.
In connection with the East Bay Complex production payment, Enron Finance
Corp. ("Enron") obtained from the Company the right to acquire during a ten-year
period commencing January 1, 1996 (or upon a registration of securities), at a
nominal cost, a one-eighth working interest in the East Bay Complex or a 9%
interest in LLC (the "Enron Option"). If the working interest was acquired, it
would have been burdened by its share of the production payment. For accounting
purposes, the total proceeds received by the Company from ERAC related to the
East Bay Complex production payment were allocated between deferred revenue from
the sale of the production payment interest ($95.7 million) and a reduction in
the full cost pool resulting from the sale of a portion of the Company's
interest in East Bay Complex ($7.5 million) based upon the relationship of
one-eighth of post-January 1, 1996 reserves to total reserves, as determined at
the date of acquisition. The production payment volumes attributed to this
interest were 401 MBbls and 1,369 MMcf. Reserve information for 1993 presented
in Note 15 and production payment volumes reflected above are presented net of
this one-eighth interest. In December 1994 Enron contributed its Enron Option
and $1,000 in
F-11
<PAGE> 112
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
exchange for one million shares of the Company's common stock. As a result of
the exchange, the Company recorded a $7.5 million increase to oil and gas
properties as well as an increase of $7.5 million for the related production
payment obligation, which were originally reduced from the respective accounts.
Concurrent with the Initial Offerings, the Company repurchased the
production payment interests. The cost to acquire the production payment
liability exceeded its book value by approximately $15.7 million. This excess
represented the difference between the amount paid and the book value of the
production payment liability as of December 7, 1994. This excess was recorded as
an expense in the period acquired.
5. RESTRICTED DEPOSITS
The Company, as the operator of the acquired oil and gas properties, is a
party to two escrow agreements. The first, related to East Bay, requires monthly
deposits of $100,000 through June 30, 1998, and $350,000 thereafter until the
balance in the escrow account equals $40 million unless the Company commits to
the plug and abandonment of a certain number of wells in which case the increase
will be deferred. The second agreement, related to Main Pass, required an
initial deposit of $250,000 and monthly deposits thereafter of $50,000 until the
balance in the escrow account equals $7,500,000. These deposits are to provide
for the future plugging and abandonment costs associated with the oil and gas
properties. Such funds are restricted as to withdrawal by the agreements. With
respect to any specifically planned plugging and abandoning operation, funds are
partially released when the Company presents to the escrow agent the planned
plugging and abandoning operations approved by the applicable governmental
agency, with the balance released upon the presentation by the Company to the
escrow agent of evidence from the governmental agency that the operation was
conducted in compliance with applicable laws and regulations. The escrow agent
for both agreements is an unrelated financial institution. As of December 31,
1995 and 1994, the escrow balances were approximately $4.3 million and $2.3
million, respectively.
6. INCOME TAXES
The Company was formed as a subchapter S corporation under the Internal
Revenue Code and, as such, all income taxes were the obligation of the Company's
stockholders. Therefore, through December 7, 1994, no historical federal or
state income tax expense has been provided for in the financial statements. In
conjunction with the Initial Offerings, the Company converted to a subchapter C
corporation under the Internal Revenue Code.
The Company has a deferred tax asset (offset by a valuation allowance in
1994) at December 31, 1995 and 1994, as follows:
<TABLE>
<CAPTION>
1995 1994
---------- -----------
<S> <C> <C>
Net operating loss carryforward.................................... $3,849,463 $ 6,019,935
Temporary differences:
Oil and gas properties........................................... 1,734,991 (1,598,426)
Other............................................................ (892,191) 1,882,490
---------- -----------
Total deferred tax asset........................................... 4,692,263 6,303,999
Valuation allowance................................................ -- (6,303,999)
---------- -----------
Net deferred tax asset............................................. $4,692,263 $ --
========== ===========
</TABLE>
At December 31, 1995, the Company had, for federal income tax reporting
purposes, operating loss carryforwards of approximately $10 million, which
expire in 2009.
A valuation allowance is provided for that portion of the asset for which
it is deemed more likely than not that it will not be realized. Due to the
Company's losses in 1994 and the substantial volatility in oil and gas
F-12
<PAGE> 113
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
prices, management provided a valuation allowance for the entire deferred tax
asset at December 31, 1994. During the second half of 1995, due to drilling
successes and increases in oil and gas prices, the Company generated income from
operations. Based upon current estimates, management believes it is more likely
than not that the deferred tax asset as of December 31, 1995, will be realized.
The principal reasons for the differences between income taxes computed at
the statutory federal income tax rate and the income tax benefit are as follows:
<TABLE>
<CAPTION>
1995 1994
---------------------------- ----------------------------
PERCENT OF NET PERCENT OF NET
INCOME BEFORE INCOME BEFORE
AMOUNT INCOME TAXES AMOUNT INCOME TAXES
----------- -------------- ----------- --------------
<S> <C> <C> <C> <C>
Income tax expense (benefit) computed at
the statutory federal income tax rate.... $ 1,823,511 35 $(7,762,491) (35)
Increase (decrease) attributable to:
Nontaxable period........................ -- -- 1,622,168 8
Cumulative temporary differences upon
conversion to a "C" corporation.......... -- -- (729,312) (3)
Change in valuation allowance.............. (6,303,999) (121) 6,303,999 28
Other...................................... (211,775) (4) 565,636 2
------------ --------- ----------- ----
Income tax benefit......................... $(4,692,263) (90) $ -- --
=========== ========= =========== ====
</TABLE>
7. STOCKHOLDERS' EQUITY
In February 1994, the Company agreed to re-acquire 1,000 shares of stock
from a former stockholder discussed in Note 1, for a total of $10 million (two
notes in the amount of $5 million each). The notes bore interest at 8% and were
paid on March 1, 1995. In March 1994, the other former stockholder discussed in
Note 1 (the plaintiff) filed suit against the Company to exercise his right to a
valuation of his 1,000 shares of stock as of December 27, 1993. This right was
triggered in a corporate transaction as allowed under Louisiana Corporation law.
The plaintiff claimed a valuation of $12.5 million, made certain other
allegations and also requested payment of attorneys' fees. The Company settled
this suit on June 30, 1994 whereby the former stockholder transferred his shares
of stock to the Company and released any claims, in exchange for $8.7 million.
In June 1994, the Company paid the former stockholder $5 million and reflected
the remainder as current notes payable until December 7, 1994 when the balance
was paid in full with a portion of the proceeds of the Initial Offerings.
As discussed in Note 6, concurrent with the closing of the Initial
Offerings, the Company converted from a subchapter S corporation to a subchapter
C corporation under the Internal Revenue Code. Effective as of that date, the
accumulated deficit of $6,688,596 has been reclassified to additional paid-in
capital. This amount had previously been reflected as a component of retained
earnings (deficit) in the December 31, 1994 financial statements.
The Company anticipates offering four million common shares to the public
in March 1996 (the "Offering"). The proceeds are expected to be used to fund
exploration and exploitation drilling activities and for possible future
acquisitions, as well as for other general corporate purposes. The Company also
intends to use approximately $15.5 million to repay the Shell Note. Pending such
application of the net proceeds, the Company intends to repay all outstanding
indebtedness under the Revolving Credit Facility with any excess proceeds to be
invested in short-term interest-bearing instruments.
F-13
<PAGE> 114
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. RELATED PARTY TRANSACTIONS
Effective July 1, 1994, the Company acquired indirectly from stockholders,
various overriding royalty interests for $1.2 million.
During 1993, the Company loaned a total of $1,250,000 to three
stockholders. The loans were represented by promissory notes which bore interest
at 8% per annum and were due upon demand, and if no demand, then by December 31,
1994. During 1994, the Company forgave $500,000 due from each of two
stockholders. On March 1, 1995, $250,000 due from a former stockholder was
received.
In July 1994, the Company purchased a portion of the overriding royalty
interests previously assigned to an affiliate of a stockholder for $3 million
(See Note 3). At that time, two stockholders loaned the Company $5 million to
make a payment to a former stockholder (See Note 7). In September 1994, the
stockholder affiliate exercised its right to repurchase the overriding royalty
interest from the Company for $3 million and the Company repaid $3 million of
the loans by the stockholders. The Company utilized a portion of the net
proceeds of the Initial Offerings to repay the remaining $2 million in loans to
stockholders.
During 1995, 1994 and 1993 the Company paid $1,041,088, $635,960, and
$499,737, respectively, to an affiliate of a stockholder associated with an
overriding royalty interest owned by it. In addition, during 1995 and 1994, the
Company paid $4,753 and $124,376, respectively, with respect to oil and gas
properties previously operated by the affiliate. These amounts are included in
accounts receivable from stockholders at December 31, 1995 and 1994.
During 1993 and 1994, the Company contracted with oilfield service
companies previously owned by current and former stockholders. The total amounts
paid for these services were $339,514 during 1993 and $1,091,152 during the
first six months of 1994 (at June 30, 1994, the stockholders assigned their
interest in such companies to a former stockholder). The Company believes that
the cost of such services would have been substantially similar to costs that
would have been charged by unaffiliated third parties for such services.
Prior to joining the Company in 1993, an officer of the Company and an
entity affiliated with him (collectively the "officer"), provided geological
consulting services for the Company. The Company paid approximately $106,000 to
the officer for services rendered in 1993 in connection with the acquisition of
the East Bay Complex. During 1994, the Company was assigned an oil and gas
prospect from the officer, who retained an overriding royalty interest. In
addition, the Company paid the officer $50,000 for services rendered in
connection therewith as well as $108,000 to a third party for acquisition of the
leases.
During 1994, the Company obtained a loan from Union Planters Bank in
connection with the purchase of a seaplane. During 1995, Mr. Flores was named a
member of the Board of Directors of that bank. The loan was made to the Company
for the amount of $132,500, bearing interest at the Wall Street Prime rate.
Principal and interest payments are payable monthly, with the balance due on
January 10, 1997. The outstanding principal balance plus accrued interest at
December 31, 1995, was $106,478. In addition, Union Planters Bank is a member of
the syndicate under the Revolving Credit Facility.
Effective November 1, 1995, the Company entered into a consulting agreement
for geological services with a party related to an officer of the Company. The
term of this agreement expires on October 31, 1996. In 1995, the Company paid
$5,200 pursuant to the agreement as well as $5,000 for other miscellaneous
geological consulting services received. In addition, in 1995 the Company paid
$50,000 for services rendered in connection with an oil and gas prospect
assigned to it by such party.
F-14
<PAGE> 115
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. LONG-TERM DEBT
Long-term loans consisted of the following at:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
Note payable to Shell, including accrued interest of $2,183,735
and $1,289,789 in 1995 and 1994, respectively, with interest
payable at a rate of 6% per annum principal and interest due
June 10, 1996, collateralized by the vendor's lien and
privilege retained by Shell which is subordinate to the
Revolving Credit Facility (management intends to refinance a
substantial portion of this note under the Revolving Credit
Facility)..................................................... $ 15,183,735 $ 14,289,789
$50,000,000 revolving line of credit with a bank, bearing
interest at a weighted average interest rate of 7.3% and 7.6%
at December 31, 1995 and 1994, respectively, as further
described below, collateralized by first mortgage on the Main
Pass and East Bay properties.................................. 32,200,000 4,500,000
Senior unsecured notes bearing interest at 13 1/2% payable
semi-annually on June 1 and December 1 of each year,
commencing June 1, 1995, due December 1, 2004................. 125,000,000 125,000,000
Promissory note to Union Planters Bank bearing interest at Wall
Street Prime due January 10, 1997, collateralized by a Company
owned seaplane................................................ 106,478 119,670
Capital lease from Finova Manufacturer Services due August 1997,
collateralized by certain computer equipment.................. 85,078 129,810
------------ ------------
Total loans........................................... 172,575,291 144,039,269
Less: Current portion -- interest payable............. 883,735 --
------------ ------------
Total long-term loans................................. $171,691,556 $144,039,269
============ ============
</TABLE>
The Revolving Credit Facility is committed for a five-year period expiring
December 31, 2000. The Revolving Credit Facility had an initial borrowing base
of $50 million. Chase Manhattan Bank, N.A. (the "Agent"), with the concurrence
of majority lenders (as defined in the $50,000,000 Credit Agreement among Flores
& Rucks, Inc. and Chase Manhattan Bank, N.A.) (the "Credit Agreement"), can
redetermine the borrowing base at its option once within any 12-month period as
well as on scheduled redetermination dates as outlined in the Credit Agreement.
The borrowing base automatically reduces by an amount equal to one-sixteenth
(1/16) of the borrowing base in effect on each quarter beginning March 31,
1997. In addition, the borrowing base may be reduced if the Company sells a
portion of its oil and gas properties. As of December 31, 1995, the borrowing
base under the Revolving Credit Facility remained at $50 million.
The Company's ability to draw additional amounts on the Revolving Credit
Facility is limited to the extent that adjusted consolidated net tangible assets
(as defined in the Credit Agreement) minus certain net production revenue (as
defined in the Credit Agreement) exceeds 100% (110% after June 1, 1996) of all
indenture indebtedness (as defined in the Credit Agreement). Adjusted
consolidated net tangible assets is determined quarterly, utilizing certain
financial information, and is primarily based on a quarterly estimate of the
present value of future net revenues of the Company's proved oil and gas
reserves. Such quarterly estimates utilize the most recent year end oil and gas
prices and vary based on additions to proved reserves and net production. As of
December 31, 1995, the Company's outstanding balance (including letters of
credit of $3.5 million) was $35.7 million and the Company had remaining
availability of $14.3 million under the Revolving Credit Facility.
F-15
<PAGE> 116
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On March 1, 1995, the Company repaid with borrowings under the Revolving
Credit Facility the two $5 million loans discussed in Note 7.
At the Company's option, borrowings under the Revolving Credit Facility
bear interest either at the base rate (the higher of the federal funds rate plus
0.5% per annum or the Agent's prime commercial lending rate) or the London
Interbank Offered Rate ("LIBOR"), in each case plus the applicable margin. The
applicable margin will be from 125 to 175 basis points for LIBOR loans and from
zero to 50 basis points for the base rate loans. Such basis points increase as
the Company increases the percentage usage of the borrowing base. As of December
31, 1995, the Company had a total balance outstanding of $32.2 million, $30.0
million of which bore interest at a LIBOR rate (including the applicable margin
based on the outstanding balance) of 7.2% and $2.2 million of which bore
interest at a base rate (including the applicable margin based on the
outstanding balance) of 8.8%, resulting in a weighted average interest rate of
7.3%. As of December 31, 1994, the Company had a balance of $4.5 million
outstanding, all of which bore interest at a LIBOR rate (including the
applicable margin based on the outstanding balance) of 7.6%.
The loan agreement for the Revolving Credit Facility contains restrictive
covenants substantially similar to those for the Senior Notes. The Revolving
Credit Facility also includes certain additional covenants and restrictions
relating to the activities of the Company which are customary for similar credit
facilities and are not expected to have a material adverse effect on the conduct
of the Company's business.
The Indenture relating to the Senior Notes contains certain covenants,
including, with limitation, covenants with respect to the following matters: (i)
limitation on indebtedness; (ii) maintenance of adjusted consolidated net
tangible assets, as defined; (iii) limitation on restricted payments; (iv)
limitation on issuances and sales of restricted subsidiary stock; (v) limitation
on sale/leaseback transactions; (vi) limitation on transactions with affiliates;
(vii) limitation on liens; (viii) disposition of proceeds of asset sales; (ix)
limitation on dividends and other payment restrictions affecting subsidiaries;
and (x) limitation of mergers, consolidations and transfers of assets.
Aggregate minimum principal payments for debt and the capital lease at
December 31, 1995, for the next five years are as follows:
<TABLE>
<S> <C>
1996.................................... $ 947,883
1997.................................... 9,127,408
1998.................................... 12,500,000
1999.................................... 12,500,000
2000.................................... 12,500,000
-----------
$47,575,291
===========
</TABLE>
On June 11, 1994, LLC entered into two loan agreements with Joint Energy
Development Investments Limited Partnership ("JEDI"), a venture between
California Public Employees Retirement System and Enron Capital Corp. The first
was a $20 million term loan, bearing interest at 12.5% payable monthly, maturing
on June 11, 1997. The second loan, the development loan, provided for draws up
to a maximum of $40 million, bearing interest at 15% payable monthly. In
connection with this loan, LLC conveyed to JEDI a 20% overriding royalty
interest (defined to be net of production costs) on certain unevaluated
interests (computed prior to the one-eighth override conveyed to a related party
discussed in Note 3) which commenced upon payment in full of the development
loan. This interest was purchased from JEDI in December 1994, for $4.25 million.
Proceeds from the Initial Offerings were used to repay these loans in December
1994.
F-16
<PAGE> 117
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. EMPLOYEE BENEFIT PLANS
The Company has a 401(K) plan which covers all employees. The Company's
contributions to the plan during 1995, 1994 and 1993 were $513,690, $432,202 and
$69,000, respectively.
Prior to consummation of the Initial Offerings, the Board of Directors
adopted and the stockholders approved a long-term incentive plan. The plan
provides for not more than 1,500,000 shares of common stock to be issued to
employees and directors of the Company. Upon consummation of the Initial
Offerings, the Company issued 645,000 stock options with an exercise price of
$10.00 per share, the fair value at the date of grant. The options vest equally
over a three-year period and terminate ten years from date of grant. On August
9, 1995 the Company's Board of Directors adopted a long-term incentive plan for
non-executive employees. The non-executive plan provides for not more than
300,000 shares of common stock to be issued to non-executive employees of the
Company during any calendar year. A summary of the stock options outstanding
under both plans follows:
<TABLE>
<CAPTION>
NUMBER OF AVERAGE
OPTIONS OPTION PRICE
--------- ------------
<S> <C> <C>
Balance at January 1, 1995................................... 645,000 $10.00
Granted...................................................... 856,500 11.97
Cancelled.................................................... (6,000) 9.38
Exercised.................................................... -- --
Expired...................................................... -- --
--------- ------
Balance at December 31, 1995................................. 1,495,500 $11.13
========= ======
</TABLE>
At December 31, 1995, stock options representing 261,667 shares were
exercisable at an average option price of $10.31 per share.
In October 1995, the FASB issued Statement of Financial Accounting
Standards No. 123 (SFAS 123), "Accounting for Stock-Based Compensation,"
effective for the Company for 1996. Under SFAS 123, companies can either record
expense based on the fair value of stock-based compensation upon issuance or
elect to remain under the current Accounting Principles Board ("APB") Opinion
No. 25 method whereby no compensation cost is recognized upon grant if certain
requirements are met. The Company intends to continue to account for its
stock-based compensation plans under APB Opinion No. 25.
In addition, in 1995, the Company issued 4,125 shares of stock which are
considered bonus shares.
The Company is self-insured for employee medical benefits up to certain
stop-loss limits.
The Company has no other significant formal benefit plans.
11. MAJOR CUSTOMERS
The Company sold the majority of its oil and gas to a few customers based
on long-term contracts in 1995 and prior years. Sales to the following customers
exceeded 10% of revenues during the years indicated (expressed in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- -------
<S> <C> <C> <C>
Enron Corp., its subsidiaries and affiliates.......... $17,431 $73,658 $46,126
Shell Oil Company..................................... 79,927 -- --
Murphy Oil USA, Inc................................... 24,193 -- --
</TABLE>
Enron Finance Corp., a subsidiary of Enron Corp., owned 1,000,000 shares or
6.6% of the Company's common stock as of December 31, 1995.
F-17
<PAGE> 118
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. COMMITMENTS AND CONTINGENCIES
While the Company is a defendant in various lawsuits in the ordinary course
of business, management believes the potential liability in such lawsuits is not
material. The Company maintains liability and other insurance customary in its
business. The Company is also subject to contingencies as a result of
environmental laws and regulations. The related future cost is indeterminable
due to such factors as the unknown timing and extent of the corrective actions
that may be required and the application of joint and several liability.
However, the Company believes that such costs will not have a material adverse
effect on its operations or financial position.
The Company, as operator, is responsible for payment of plugging and
abandonment costs on its properties. As of December 31, 1995, the total estimate
of these costs on the East Bay Complex and Main Pass 69 was approximately $55
million, estimated to be incurred through the year 2007. The provision for such
costs is recorded through depreciation, depletion and amortization expense. The
estimates of plugging and abandonment costs and their timing may change due to
many factors including, among others, actual production results, inflation
rates, and changes in environmental laws and regulations.
In August 1993, the Minerals Management Service ("MMS") provided notice to
lessees of Outer Continental Shelf ("OCS") leases that new levels of lease and
area wide bonds would be required effective November 26, 1993, in connection
with the plugging and abandoning of wells located offshore and the removal of
all production facilities. The coverage is designed to reflect an appropriate
balance between encouraging the maximum economic recovery of oil and natural gas
from federal offshore leases while providing the federal government an adequate
level of protection in the event the lessee defaults on its obligations to
properly abandon lease wells and remove platforms and other structures from the
property.
The MMS requires lessees of OCS properties to post 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
currently required to post area wide bonds of $3 million or $500,000 per
producing lease and supplemental bonds at the discretion of the MMS. On January
17, 1995, the Company entered into an agreement with Planet Indemnity Company
("Planet") whereby Planet agreed to issue $11.7 million of MMS surety bonds for
the Company and the Company agreed to post collateral for same in favor of
Planet. The collateral includes a mortgage on the Company's federal OCS leases
in the amount of $8.2 million, a letter of credit for $3.5 million and a pledge
of certain rights to escrowed funds. The Company has posted a total of
$13,275,000 of bonds with the MMS and has satisfied all requirements for bonds
imposed to date by the MMS. Pursuant to a schedule imposed by the MMS, the
Company will be required to post additional bonds up to a total bonding level of
$24.6 million by January 1999, unless the Company is determined by the MMS to be
exempt from such requirement due to certain financial tests. The Company does
not anticipate that the cost of any such bonding requirements will materially
affect the Company's financial position. Under certain circumstances, the MMS
may require any Company operations on federal leases to be suspended or
terminated. Any such suspensions or terminations could have a material adverse
effect on the Company's financial condition and operations. The MMS also intends
to adopt financial responsibility regulations under the Oil Pollution Act of
1990 (the "OPA").
The OPA regulations impose a variety of regulations on "responsible
parties" related to the prevention of oil spills and liability for damages
resulting from such spills in United States waters. A "responsible party"
includes the owner or operator of a facility or vessel, or the lessee or
permittee of an area in which an offshore facility is located. The OPA assigns
liability to each responsible party for oil removal costs and a variety of
public and private damages. While liability limits apply in some circumstances,
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 the OPA.
F-18
<PAGE> 119
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. On August 25, 1993, the MMS published an advance notice of its intention
to adopt regulations under the Oil Pollution Act of 1990 ("OPA 90") that would
require owners and operators of offshore oil and natural gas facilities to
establish $150 million in financial responsibility in case of a potential spill.
In May 1995, the U.S. House of Representatives approved a bill that would amend
OPA 90 to reduce the level of financial responsibility to $35 million. The U.S.
Senate passed a related measure on November 17, 1995, that would also amend OPA
90 to reduce the level of financial responsibility to $35 million. The Clinton
Administration has expressed its support for this legislation, but has not yet
taken any action on the bills approved by the U.S. House of Representatives and
the U.S. Senate. The MMS has indicated that it would not move forward with the
adoption of the rule until the United States Congress has had an opportunity to
act on the pending amendments to OPA 90. Based on the passage of these bills and
the support of the Clinton Administration, it appears that the level of
financial responsibility required under OPA 90 will be reduced and the MMS will
probably not move forward with the adoption of its rule as it was proposed.
Under the proposed rule, financial responsibility could be established through
insurance, guaranty, indemnity, surety bond, letter of credit qualifications as
a self-insurer or a combination thereof. There is substantial uncertainty as to
whether insurance companies or underwriters will be willing to provide coverage
under the OPA because the statute provides for direct lawsuits against insurers
who provide financial responsibility coverage, and most insurers have strongly
protested this requirement. The financial tests or other criteria that will be
used to judge self-insurance are also uncertain. The Company cannot predict the
final form of the financial responsibility rule that will be adopted by the MMS,
but such rule has the potential to result in the imposition of substantial
additional annual costs on the Company or otherwise materially adversely affect
the Company. The impact of the rule should not be any more adverse to the
Company than it will be to other similarly situated owners or operators in the
Gulf of Mexico region.
The Company's minimum annual contractual charges as of December 31, 1995,
under noncancellable operating leases were as follows:
<TABLE>
<S> <C>
1996.............................................................. $319,343
1997.............................................................. 227,386
--------
$546,729
========
</TABLE>
Total rental expenses under operating leases amounted to approximately
$527,000, $297,000 and $166,000 in 1995, 1994 and 1993, respectively.
In connection with the Initial Offerings, the Company entered into a
Registration Rights Agreement whereby Enron is entitled to require the Company
to register common stock of the Company owned by Enron with the Securities and
Exchange Commission (the "SEC") for sale to the public in a public offering, at
no cost to Enron except for discounts and commissions, if any.
13. HEDGING ACTIVITIES
The Company hedges certain of its production through a master swap
agreement ("Swap Agreement") with Enron Capital & Trade Resources Corp. ("ECT").
The Swap Agreement provides for separate contracts tied to the NYMEX light sweet
crude oil and natural gas futures contracts. During 1995 and 1993, the Company
unwound certain contracts entered into under the Swap Agreement for barrels
hedged. The gain realized upon unwinding these transactions has been deferred
and is being amortized over the original determination period on a
units-of-production basis. No contracts were unwound during 1994. The Swap
Agreement is settled monthly based on the differences between contract prices
and the average NYMEX prices for that month applied to the related contract
volumes. To the extent the NYMEX price exceeds the contract price the Company
pays the spread to ECT, and to the extent the contract price exceeds the NYMEX
price ECT pays the spread to the Company. Under the terms of the Swap Agreement,
if the
F-19
<PAGE> 120
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's exposure (i.e., the cost to buyout all of the contracts covered by the
Swap Agreement) exceeds $5 million, ECT can require the Company to establish and
maintain a letter of credit for the amount of such excess, rounded up to the
next multiple of $500,000. As of December 31, 1995, the Company's exposure under
all contracts covered by the Swap Agreement was approximately $1.5 million.
As of February 16, 1996, the Company's open forward position with ECT was
as follows:
<TABLE>
<CAPTION>
OIL GAS
----------------- ------------------
AVERAGE AVERAGE
YEAR MBBLS PRICE (BBTU) PRICE
------------------------ ----- ------- ------ -------
<S> <C> <C> <C> <C>
1996.................... 1,100 $ 18.43 8,200 $1.90
1997.................... 300 18.55 -- --
1998.................... 300 18.55 -- --
1999.................... 300 18.55 -- --
2000.................... 300 18.55 -- --
----- ------ ----- -----
Total......... 2,300 $ 18.49 8,200 $1.90
===== ====== ===== =====
</TABLE>
The above table assumes extendible contracts have not been exercised by
ECT. However, included in the 1996 swap agreements are two three-month term
hedges with a nine-month option exercisable by ECT. If ECT exercises its option
to extend, total barrels would increase to 2,900 MBbls in 1996. The average
price for the year ending December 31, 1996, assuming all extendible contracts
are exercised is $18.33.
Revenue was increased (decreased) under the Swap Agreements by
approximately $(0.5) million, $1.7 million and $1.2 million, respectively, for
the years ended December 31, 1995, 1994 and 1993.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value as of December 31, 1995 and 1994, of financial
instruments other than current assets and liabilities is presented in the
following table:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------------------------------------
1995 1994
------------------------------ ------------------------------
ESTIMATED ESTIMATED
BOOK VALUE FAIR VALUE BOOK VALUE FAIR VALUE
------------- ------------- ------------- -------------
ASSET (LIABILITY)
<S> <C> <C> <C> <C>
Debt
Senior Notes.......... $(125,000,000) $(141,875,000) $(125,000,000) $(125,312,500)
Shell Note............ (15,183,735) (15,094,232) (14,289,789) (13,737,218)
Revolving Credit
Facility........... (32,200,000) (32,200,000) (4,500,000) (4,500,000)
------------- ------------- ------------- -------------
$(172,383,735) $(189,169,232) $(143,789,789) $(143,549,718)
============= ============= ============= =============
Hedges
Gas................... $ -- $ (2,423,240) $ -- $ 162,300
Oil................... -- 950,750 -- (2,233,200)
------------- ------------- ------------- -------------
$ -- $ (1,472,490) $ -- $ (2,070,900)
============= ============= ============= =============
</TABLE>
15. OIL AND GAS RESERVE INFORMATION -- UNAUDITED
The Company's net proved oil and gas reserves at December 31, 1995, 1994
and 1993, have been determined by independent petroleum consultants in
accordance with guidelines established by the SEC and the FASB. Accordingly, the
following reserve estimates are based upon existing economic and operating
conditions at the respective dates. Future cash flows from oil and natural gas
reserves were computed on the basis of prices being received at year end for oil
and natural gas, adjusted for hedges in place at that date. The 1993 estimates
have been adjusted to exclude (i) volumes (approximately 9.7 million equivalent
barrels of oil as of December 31, 1993) and (ii) future revenues associated with
the production payments discussed in Note 4 and approximately 3.1 million
equivalent barrels of oil (net of the related production payment of 0.8 million
equivalent barrels) and approximately $1.0 million of standardized measure of
discounted future net cash flows associated with the Enron Option.
F-20
<PAGE> 121
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
There are many uncertainties inherent in estimating quantities of proved
reserves and in providing the future rates of production and timing of
development expenditures. The following reserve data represent estimates only
and should not be construed as being exact. In addition, the present values
should not be construed as the current market value of the Company's oil and gas
properties or the cost that would be incurred to obtain equivalent reserves.
The following tables set forth an analysis of the Company's estimated
quantities of net proved and proved developed oil (includes condensate) and gas,
all located offshore in the continental United States:
<TABLE>
<CAPTION>
OIL NATURAL GAS
(MBBL) (MMCF)
------ -----------
<S> <C> <C>
Proved reserves as of December 31, 1992......................... 7,270 9,090
Revisions of previous estimates............................... (2,817) 314
Purchase of producing properties.............................. 27,505 37,997
Sale of production payment.................................... (5,950) (14,486)
Sale of producing properties.................................. (3,378) (5,149)
Production.................................................... (1,537) (1,705)
------ -------
Proved reserves as of December 31, 1993......................... 21,093 26,061
Revisions of previous estimates............................... 1,979 (4,667)
Extensions, discoveries, and other additions.................. 688 2,775
Repurchase of production payment.............................. 6,111 19,523
Purchase of producing properties.............................. 5,944 7,708
Production.................................................... (2,771) (3,456)
------ -------
Proved reserves as of December 31, 1994......................... 33,044 47,944
Revisions of previous estimates............................... 4,857 4,293
Extensions, discoveries, and other additions.................. 1,640 10,647
Purchase of producing properties.............................. 345 85
Production.................................................... (6,057) (12,393)
------ -------
Proved reserves as of December 31, 1995......................... 33,829 50,576
====== =======
Proved developed reserves:
As of December 31, 1993....................................... 17,999 20,764
As of December 31, 1994....................................... 30,088 42,668
As of December 31, 1995....................................... 31,702 48,635
</TABLE>
F-21
<PAGE> 122
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table presents the standardized measure of future net cash
flows related to proved oil and gas reserves together with changes therein, as
defined by the FASB. The oil, condensate and gas price structure utilized to
project future net cash flows reflects current prices at each year end adjusted
for hedges in place at that date and have been escalated only where known and
determinable price changes are provided by contracts and law. Future production
and development costs are based on current costs with no escalations. Estimated
future cash flows have been discounted to their present values based on a 10%
annual discount rate.
<TABLE>
<CAPTION>
STANDARDIZED MEASURE
AS OF DECEMBER 31,
-------------------------------------
1995 1994 1993
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash flows....................................... $ 762,488 $ 645,091 $ 349,112
Future production, development and abandonment costs.... (482,658) (433,193) (343,427)
Income tax provision.................................... (36,712) (11,530) --
--------- --------- ---------
Future net cash flows................................... 243,118 200,368 5,685
10% annual discount..................................... (39,178) (35,390) 7,490
--------- --------- ---------
Standardized measure of discounted future net cash
flows................................................. $ 203,940 $ 164,978 $ 13,175
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
CHANGES IN STANDARDIZED MEASURE
PERIODS ENDED DECEMBER 31,
---------------------------------
1995 1994 1993
-------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure at beginning of period................. $164,978 $ 13,175 $ 24,611
Sales and transfers of oil and gas produced, net of
production costs.......................................... (87,924) (21,214) (9,851)
Changes in price, net of future production costs............ 61,865 34,412 (52,191)
Extensions and discoveries, net of future production and
development costs......................................... 46,429 14,397 --
Repurchase of production payment............................ -- 106,572 --
Sale of production payment.................................. -- -- (103,616)
Sale of reserves............................................ -- -- (17,919)
Previously estimated development and abandonment costs
incurred during the period................................ 19,132 8,606 8,110
Revisions of quantity estimates............................. 46,761 8,184 (7,435)
Accretion of discount....................................... 17,474 2,352 5,965
Net change in income taxes.................................. (21,034) (9,762) --
Purchase of reserves in place............................... 3,193 17,564 181,661
Changes in production rates (timing), estimated development
and abandonment costs, and other.......................... (46,934) (9,308) (16,160)
-------- -------- ---------
Standardized measure at end of year......................... $203,940 $164,978 $ 13,175
======== ======== =========
</TABLE>
F-22
<PAGE> 123
FLORES & RUCKS, INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
ASSETS
<TABLE>
<CAPTION>
JUNE 30,
1996
-------------
<S> <C>
Current assets:
Cash and cash equivalents................................................... $ 819,468
Joint interest receivables.................................................. 1,229,810
Oil and gas sales receivables............................................... 16,112,617
Notes and accounts receivable -- stockholders............................... --
Accounts receivable -- other................................................ 3,700,000
Prepaid expenses............................................................ 1,019,583
Other current assets........................................................ 1,370,150
-------------
Total current assets................................................ 24,251,628
Oil and gas properties -- full cost method:
Evaluated................................................................... 332,287,198
Less accumulated depreciation, depletion, and amortization.................. (143,013,084)
-------------
189,274,114
Unevaluated properties excluded from amortization........................... 27,106,066
Other assets:
Furniture and equipment, less accumulated depreciation of $1,891,211........ 2,793,110
Restricted deposits......................................................... 5,269,835
Deferred financing costs.................................................... 4,823,582
Deferred tax asset.......................................................... 3,202,863
-------------
Total assets........................................................ $ 256,721,198
=============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable accrued liabilities........................................ $ 37,240,733
Oil and gas sales payable................................................... 4,548,963
Accrued interest............................................................ 1,447,287
-------------
Total current liabilities........................................... 43,236,983
Long-term debt................................................................ 128,160,111
Notes payable to be refinanced under revolving line of credit................. --
Other noncurrent liabilities.................................................. 638,609
Deferred hedge revenue........................................................ 233,167
Stockholders' equity:
Preferred stock, $.01 par value; authorized 10,000,000 shares
no shares issued or outstanding at June 30, 1996......................... --
Common stock, $.01 par value; authorized 100,000,000 shares;
issued and outstanding 19,555,223 shares................................. 195,552
Paid-in capital............................................................. 89,734,455
Retained earnings (deficit)................................................. (5,477,679)
-------------
Total stockholders' equity.......................................... 84,452,328
-------------
Total liabilities and stockholders' equity.......................... $ 256,721,198
=============
</TABLE>
The accompanying notes to financial statements are an integral part of these
statements.
F-23
<PAGE> 124
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
---------------------------
1996 1995
----------- -----------
<S> <C> <C>
Revenues:
Oil and gas sales............................................... $69,115,492 $55,421,460
Plant processing income (loss).................................. (33,473) 450,459
----------- -----------
Total revenues.......................................... 69,082,019 55,871,919
Operating expenses:
Lease operations................................................ 16,522,030 14,225,302
Severance taxes................................................. 5,521,763 4,744,919
Depreciation, depletion and amortization........................ 28,973,040 23,166,908
----------- -----------
Total operating expenses................................ 51,016,833 42,137,129
General and administrative expenses............................... 6,025,000 5,613,381
Interest expense.................................................. 8,188,026 8,492,613
Other expense (income)............................................ 1,779 (120,616)
----------- -----------
Net income (loss) before income taxes............................. 3,850,381 (250,588)
Income tax expense................................................ 1,514,704 --
----------- -----------
Net income (loss)................................................. $ 2,335,677 $ (250,588)
=========== ===========
Weighted average common shares outstanding........................ 17,620,538 15,042,102
Earnings (loss) per common share.................................. $ .13 $ (.02)
</TABLE>
The accompanying notes to financial statements are an integral part of these
statements.
F-24
<PAGE> 125
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-----------------------------
1996 1995
------------ ------------
<S> <C> <C>
Operating activities:
Net income (loss)............................................. $ 2,335,677 $ (250,588)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization................... 29,606,026 23,441,656
Deferred hedge revenue..................................... (637,166) (66,667)
Deferred tax asset......................................... 1,489,400 --
Changes in operating assets and liabilities:
Accrued interest........................................... (2,503,810) 889,788
Receivables................................................ (2,976,896) (2,291,865)
Prepaid expenses........................................... (629,171) (133,145)
Other current assets....................................... (945,326) (17,100)
Accounts payable and accrued liabilities................... 22,149,942 18,676,705
Oil and gas sales payable.................................. (628,316) 393,319
------------ ------------
Net cash provided by operating activities....................... 47,260,360 40,642,103
------------ ------------
Investing activities:
Additions to oil and gas properties and furniture and
equipment.................................................. (65,856,527) (45,608,012)
Increase in restricted deposits............................... (1,010,653) (958,011)
------------ ------------
Net cash used in investing activities........................... (66,867,180) (46,566,023)
------------ ------------
Financing activities:
Sale of stock................................................. 62,141,101 369,949
Borrowings on notes payable................................... 30,000,000 42,500,020
Payments of notes payable..................................... (72,231,443) (37,528,259)
Deferred financing costs...................................... 304,392 120,801
------------ ------------
Net cash provided by financing activities....................... 20,214,050 5,462,511
------------ ------------
Increase (decrease) in cash and cash equivalents................ 607,230 (461,409)
Cash and cash equivalents, beginning of the period.............. 212,238 568,690
------------ ------------
Cash and cash equivalents, end of the period.................... $ 819,468 $ 107,281
============ ============
Interest paid during the period................................. $ 11,917,620 $ 8,781,824
============ ============
</TABLE>
The accompanying notes to financial statements are an integral part of these
statements.
F-25
<PAGE> 126
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. GENERAL INFORMATION
The consolidated financial statements included herein have been prepared by
Flores & Rucks, Inc. (the "Company") without audit and include all adjustments
(of a normal and recurring nature) which are, in the opinion of management,
necessary for the fair presentation of interim results which are not necessarily
indicative of results for the entire year. The financial statements should be
read in conjunction with the consolidated financial statements and notes thereto
included in the Company's latest annual report.
2. EARNINGS PER SHARE
Earnings per common share are based on the weighted average number of
shares of common stock outstanding for the periods. The Company had 1,865,735
stock options outstanding as of June 30, 1996. The options were not reflected as
common stock equivalents for the six months ended June 30, 1996, as the dilutive
effect caused by the options on earnings per share was less than three percent.
The Company had 760,500 options outstanding as of June 30, 1995, which were
not reflected as common stock equivalents for the six months ended June 30,
1995, as they were anti-dilutive.
3. HEDGING ACTIVITIES
The Company hedges certain of its production through a master swap
agreement ("Swap Agreement") with Enron Capital & Trade Resources Corp. ("ECT").
The Swap Agreement provides for separate contracts tied to the NYMEX light sweet
crude oil and natural gas futures contracts. The Swap Agreement is settled
monthly based on the differences between contract prices and the average NYMEX
prices for that month applied to the related contract volumes. To the extent the
NYMEX price exceeds the contract price, the Company pays the spread to ECT, and
to the extent the contract price exceeds the NYMEX price, ECT pays the spread to
the Company. Under the terms of the Swap Agreement, if the Company's exposure
(i.e., the cost to buyout all of the contracts covered by the Swap Agreement)
exceeds $5 million, ECT can require the Company to establish and maintain a
letter of credit in the amount of such excess, rounded up to the next multiple
of $500,000. As of August 2, 1996, the Company's exposure under all contracts
covered by the Swap Agreement was approximately $2.9 million.
As of June 30, 1996, the Company's open forward position with ECT was as
follows:
<TABLE>
<CAPTION>
OIL GAS
---------------- ----------------
AVERAGE AVERAGE
YEAR MBBLS PRICE BBTU PRICE
----------------------------------------------------- ----- ------- ----- -------
<S> <C> <C> <C> <C>
1996................................................. 1,550 $ 18.25 1,230 $1.97
1997................................................. 300 $ 18.55 -- --
1998................................................. 300 $ 18.55 -- --
1999................................................. 300 $ 18.55 -- --
2000................................................. 300 $ 18.55 -- --
----- ------- ----- -----
Total...................................... 2,750 $ 18.38 1,230 $1.97
===== ======= ===== =====
</TABLE>
4. COMMON STOCK OFFERING
On March 19, 1996, the Company completed a public offering of 4,500,000
shares of common stock at a price of $14.75 per share (the "Offering"). Net
proceeds of the Offering were approximately $62.2 million, of which $15.4
million was used to repay a note payable to Shell Offshore, Inc. and
approximately $33.0 million was used to repay indebtedness under the Company's
$50 million borrowing based senior revolving bank credit facility.
F-26
<PAGE> 127
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
The Board of Directors
Flores & Rucks, Inc.
We have audited the accompanying statements of combined oil and gas
revenues and direct operating expenses for certain oil and gas producing
properties to be acquired from Mobil Oil Exploration & Producing Southeast Inc.
by Flores & Rucks, Inc. (the "Company") for the years ended December 31, 1995,
1994 and 1993. These statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the accompanying statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the accompanying statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
The accompanying statements were prepared for the purpose of complying with
the rules and regulations of the Securities and Exchange Commission and are not
intended to be a complete presentation of the revenues and expenses of certain
oil and gas producing properties to be acquired from Mobil Oil Exploration &
Producing Southeast Inc.
In our opinion, the statements referred to above present fairly, in all
material respects, the operating revenues and direct operating expenses of
certain oil and gas producing properties to be acquired from Mobil Oil
Exploration & Producing Southeast Inc. by the Company for the years ended
December 31, 1995, 1994 and 1993 in conformity with generally accepted
accounting principles.
Ernst & Young LLP
Fort Worth, Texas
August 8, 1996
F-27
<PAGE> 128
CERTAIN OIL AND GAS PRODUCING PROPERTIES
TO BE ACQUIRED FROM MOBIL OIL EXPLORATION & PRODUCING SOUTHEAST INC.
STATEMENTS OF COMBINED OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES
<TABLE>
<CAPTION>
SIX MONTHS
ENDED YEAR ENDED DECEMBER 31,
JUNE 30, -----------------------------------------
1996 1995 1994 1993
----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C>
Revenues:
Crude and condensate sales............. $16,051,043 $29,508,175 $26,125,879 $28,814,207
Natural gas sales...................... 13,415,793 16,375,011 23,891,688 28,466,425
----------- ----------- ----------- -----------
29,466,836 45,883,186 50,017,567 57,280,632
Direct operating expenses:
Lease operating expenses............... 5,300,735 12,877,310 13,944,923 13,756,094
----------- ----------- ----------- -----------
Oil and gas revenues in excess of direct
operating expenses..................... $24,166,101 $33,005,876 $36,072,644 $43,524,538
=========== =========== =========== ===========
</TABLE>
See accompanying notes.
F-28
<PAGE> 129
CERTAIN OIL AND GAS PRODUCING PROPERTIES
TO BE ACQUIRED FROM MOBIL OIL EXPLORATION & PRODUCING SOUTHEAST INC.
NOTES TO STATEMENTS OF COMBINED OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES
NOTE A -- BASIS OF PRESENTATION
Pursuant to the terms of a Purchase and Sale Agreement dated as of July 10,
1996, Flores & Rucks, Inc. (the "Company") will acquire certain oil and gas
producing properties situated in the Gulf of Mexico, offshore Louisiana (the
"Mobil Interest") from Mobil Oil Exploration & Producing Southeast Inc.
("Mobil") effective August 1, 1996, after exercise of certain preferential
purchase rights by other parties.
The oil and gas revenues and direct operating expenses presented herein
relate only to the interests in the certain oil and gas producing properties
acquired and do not represent all of the costs of oil and gas operations of
Mobil. Direct operating expenses include the actual costs of maintaining the
producing properties and their production, but do not include charges for
depletion, depreciation, amortization and abandonment; federal and state income
taxes; interest; or general and administrative expenses. The oil and gas
revenues and direct operating expenses for the periods presented may not be
indicative of the results of future operations of the properties acquired.
Mobil accounts for gas revenues on the sales method. Generally, Mobil sells
its oil and gas production to other affiliates of Mobil Corporation. Crude oil
prices are based on Mobil's posted field prices for crude oil purchases in the
area. Gas prices are based on Inside FERC published prices.
NOTE B -- SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE INFORMATION
(UNAUDITED)
The Company's internal reserve engineers prepared an estimate of the future
net oil and gas reserves of the Mobil Interest as of August 1, 1996. The reserve
quantity information has been derived from this estimate.
Estimated quantities of proved net reserves include only those quantities
that can be expected to be commercially recoverable at prices and costs in
effect at the effective date of the acquisition, under existing regulatory
practices and with conventional equipment and operating methods. Proved
developed reserves represent only those reserves expected to be recovered
through existing wells with existing equipment and operating methods. Proved
undeveloped reserves include those reserves expected to be recovered from new
wells on undrilled acreage or from existing wells on which a relatively major
expenditure is required for recompletion.
ESTIMATED QUANTITIES OF PROVED RESERVES
<TABLE>
<CAPTION>
MOBIL INTEREST
-----------------------
OIL GAS
(MBBL) (MMCF)
--------- ---------
<S> <C> <C>
January 1, 1993................................................ 20,217 94,520
Production................................................... 1,799 12,226
December 31, 1993.............................................. 18,418 82,294
Production................................................... 1,741 11,352
December 31, 1994.............................................. 16,677 70,942
Production................................................... 1,816 9,887
----- -----
December 31, 1995.............................................. 14,861 61,055
===== =====
Proved developed reserves as of December 31, 1995.............. 10,244 42,415
===== =====
</TABLE>
F-29
<PAGE> 130
The following is a summary of a standardized measure of discounted future
net cash flows related to the proved oil and gas reserves of the Mobil Interest.
For these calculations, estimated future cash flows from estimated future
production or proved reserves were computed using oil and gas prices as of the
end of each period presented. Future development and production costs
attributable to the proved reserves were estimated assuming that existing
conditions would continue over the economic life of the properties, and costs
were not escalated for the future. The Mobil Interest is not a separate tax
paying entity. Accordingly, the standardized measure of discounted future net
cash flows from proved reserves is presented before deduction of federal income
taxes. The information presented below should not be viewed as an estimate of
the fair value of the Mobil Interest, nor should it be considered indicative of
any future trends.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
MOBIL INTEREST
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflows............................... $ 407,191 $ 389,840 $ 437,244
Future production and development costs........... (198,956) (214,661) (233,417)
Discount of future net cash flows at 10% per
annum........................................... (53,656) (45,383) (54,538)
-------- -------- --------
Standardized measure of discounted future net
cash flows...................................... $ 154,579 $ 129,796 $ 149,289
======== ======== ========
</TABLE>
The weighted average prices of oil and gas at December 31, 1995, 1994 and
1993 used in the above table were $18.23, $16.58 and $13.18 per barrel,
respectively, and $2.22, $1.60 and $2.36 per Mcf, respectively.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows of the Mobil Interest.
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Sales and transfers of oil and gas produced, net of
production costs................................. $(33,006) $(36,073) $(43,566)
Net changes in prices and production costs......... 52,540 (331) (48,639)
Accretion of discount.............................. 12,980 14,929 20,425
Changes in production rates, future development
costs
and other........................................ (7,731) 1,982 16,823
------- -------- --------
Net change......................................... $ 24,783 $(19,493) $(54,957)
======= ======== ========
</TABLE>
F-30
<PAGE> 131
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NO DEALER, SALESPERSON OR ANY OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFERING HEREIN, AND, IF GIVEN AND MADE, SUCH
INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY THE COMPANY OR THE UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER
TO SELL, OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THOSE
SPECIFICALLY OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION IN SUCH JURISDICTION. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY
CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION HEREIN IS CORRECT AS
OF ANY TIME SUBSEQUENT TO ITS DATE.
---------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary......................... 3
Risk Factors............................... 12
The Company................................ 19
Common Stock Offering...................... 19
Use of Proceeds............................ 19
Capitalization............................. 20
Selected Historical Financial and Operating
Data..................................... 21
Unaudited Pro Forma Consolidated Financial
Statements............................... 23
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................... 29
Business and Properties.................... 42
Management................................. 59
Description of the Notes................... 61
Underwriting............................... 95
Legal Matters.............................. 95
Experts.................................... 95
Available Information...................... 96
Incorporation of Certain Documents by
Reference................................ 97
Glossary of Certain Oil and Gas Terms...... 98
Index to Financial Statements.............. F-1
</TABLE>
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$160,000,000
[FLORES & RUCKS LOGO]
FLORES & RUCKS, INC.
9 3/4% SENIOR SUBORDINATED
NOTES DUE 2006
---------------------------
PROSPECTUS
---------------------------
MERRILL LYNCH & CO.
BEAR, STEARNS & CO. INC.
SALOMON BROTHERS INC
SEPTEMBER 20, 1996
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