OCEAN ENERGY INC, 424B4, 1997-11-14

OCEAN ENERGY INC
424B4, 1997-11-14
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

FILED PURSUANT TO RULE 424(B)(4)

REGISTRATION NO. #333-37985

PROSPECTUS

3,600,000 SHARES

[OCEAN ENERGY LOGO]

COMMON STOCK
---------------------

Of the 3,600,000 shares of Common Stock, par value $0.01 per share ("Common
Stock") of Ocean Energy, Inc., a Delaware corporation ("OEI" or the "Company")
offered hereby, 3,100,000 shares are being sold by the Company and 500,000
shares are being sold by the Selling Stockholders (as defined herein). The
Company will not receive any proceeds from the sale of the shares offered by the
Selling Stockholders. See "Selling Stockholders."

Of the shares of Common Stock being offered hereby, 2,880,000 shares (the
"U.S. Shares") are being offered in the United States and Canada (the "U.S.
Offering") by the U.S. Underwriters and 720,000 shares (the "International
Shares") are being offered outside the United States and Canada (the
"International Offering" and, together with the U.S. Offering, the "Offerings")
by the International Managers. The price to public and underwriting discount per
share are identical for both Offerings and the closings for both Offerings are
conditioned upon each other. See "Underwriting."

The Common Stock is traded on the New York Stock Exchange ("NYSE") under
the symbol "OEI." On November 12, 1997, the last reported sale price of the
Common Stock on the NYSE was $59 7/8 per share. See "Price Range of Common Stock
and Dividend Policy."

SEE "RISK FACTORS" BEGINNING ON PAGE 11 FOR CERTAIN CONSIDERATIONS RELEVANT
TO AN INVESTMENT IN THE COMMON STOCK OFFERED HEREBY.
---------------------

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 PROCEEDS TO
PUBLIC DISCOUNT(1) COMPANY(2) SELLING STOCKHOLDERS
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Per Share................. $59.875 $2.39 $57.485 $57.485
- ---------------------------------------------------------------------------------------------------------------
Total(3).................. $215,550,000 $8,604,000 $178,203,500 $28,742,500
===============================================================================================================
</TABLE>

(1) The Company and the Selling Stockholders have agreed to indemnify the
several Underwriters against certain liabilities under the Securities Act of
1933, as amended. See "Underwriting."

(2) Before deducting expenses payable by the Company estimated at $550,000.

(3) One of the Selling Stockholders has granted to the U.S. Underwriters and
International Managers an option for 30 days to purchase up to 432,000 and
108,000 additional shares of Common Stock, respectively, at the Price to
Public, less Underwriting Discount, solely to cover over-allotments, if any.
If such option is exercised in full, the Price to Public, Underwriting
Discount and Proceeds to Selling Stockholders will be $247,882,500,
$9,894,600 and $59,784,400, respectively. See "Underwriting."

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

The shares are offered by the several Underwriters, subject to prior sale,
when, as and if issued to and accepted by them, 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 shares of
Common Stock will be made in New York, New York on or about November 18, 1997.

---------------------
MERRILL LYNCH & CO. LEHMAN BROTHERS

HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
MORGAN STANLEY DEAN WITTER
PETRIE PARKMAN & CO.
SMITH BARNEY INC.
---------------------

THE DATE OF THIS PROSPECTUS IS NOVEMBER 12, 1997.

<PAGE> 2

MERRILL LYNCH SPECIALISTS INC. ("MLSI"), AN AFFILIATE OF MERRILL LYNCH,
PIERCE, FENNER & SMITH INCORPORATED, ONE OF THE UNDERWRITERS, ACTS AS A
SPECIALIST IN THE COMMON STOCK OF THE COMPANY PURSUANT TO THE RULES OF THE NEW
YORK STOCK EXCHANGE, INC. UNDER AN EXEMPTION GRANTED BY THE SECURITIES AND
EXCHANGE COMMISSION ON JULY 31, 1995, MLSI WILL BE PERMITTED TO CARRY ON ITS
ACTIVITIES AS A SPECIALIST IN THE COMMON STOCK FOR THE ENTIRE PERIOD OF THE
DISTRIBUTION OF THE COMMON STOCK. THE EXEMPTION IS SUBJECT TO THE SATISFACTION
BY MLSI OF THE CONDITIONS SPECIFIED IN THE EXEMPTION.

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK 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 "OEI" or the "Company" are to Ocean Energy, Inc., a Delaware
corporation, its predecessors and their respective subsidiaries. On June 17,
1997, the Company changed its name from Flores & Rucks, Inc. to Ocean Energy,
Inc. The estimates of the Company's proved reserves as of December 31, 1996 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 September 30, 1997 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 "Disclosure Regarding Forward-Looking Statements" and "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. OEI has
one of the most active exploration and development programs in the Gulf of
Mexico, which is among the most prolific oil and gas producing regions in the
United States. The Company has increased its average daily production by 222% to
48,379 BOE for the three months ended September 30, 1997 from 15,047 BOE for the
year ended December 31, 1994. EBITDA (as defined herein) increased 90% to $144.8
million for the nine months ended September 30, 1997 from $76.4 million for the
same period of 1996. As of September 30, 1997, the Company had estimated proved
reserves of approximately 63.8 MMBbls of oil and 187.6 Bcf of natural gas, or an
aggregate of approximately 95.0 MMBOE, an increase of 27% from 75.0 MMBOE at
December 31, 1996. Over 90% of the Company's existing proved reserves are
attributable to Company operated wells or leases, and approximately 80% of these
reserves were classified as proved developed at September 30, 1997. Further, the
Company has identified 665 reserve and production enhancement opportunities on
its existing properties.

In order to reduce risk, the Company uses state-of-the-art seismic
evaluation technology in its exploration and development activities. The seismic
evaluation technology is integrated with subsurface data to improve the
Company's ability to properly define the structural and stratigraphic features
that potentially contain hydrocarbon accumulations. As of September 30, 1997,
the Company owned or licensed approximately 1,700 square miles of 3-D seismic
data and over 32,000 linear miles of 2-D seismic data on and around its core
properties. With the aid of seismic technology, the Company has achieved an 88%
success rate on 129 wells drilled in the Gulf of Mexico since its inception
(April 20, 1992).

The Company's activities have historically been focused primarily in three
geographically distinct areas in the Gulf of Mexico region, consisting of the
Company's holdings in the Mississippi River Delta area (the "Delta Area"), the
Central Gulf of Mexico area (the "Central Gulf Area"), and onshore Louisiana
(the "Onshore Exploratory Area"). Most recently, the Company has become active
in deepwater (water depth over 1,000 feet) areas of the Gulf of Mexico (the
"Deepwater Gulf") through both its joint venture with Conoco, Inc. ("Conoco")
and its high bid in a recent federal lease sale on six blocks in the Keathley
Canyon area of the Deepwater Gulf ("Keathley Canyon").

Area consists of leasehold and seismic lease options totaling 51,653 gross
(36,459 net) acres. These 18 offshore fields, together with the Onshore
Exploratory Area, provide significant opportunities to enhance current
production and ultimate reserve recoveries through exploratory and development
drilling, recompletions and infill and horizontal drilling.

As part of an increased emphasis on reserve additions through exploratory
drilling, the Company has begun to focus on the deepwater areas of the Gulf of
Mexico. Based on the magnitude of recent discoveries by other companies, the
Company believes that exploration in the Deepwater Gulf affords it the
opportunity to discover significantly larger potential reserves and to earn a
high rate of return, complementing its lower risk opportunities in the shallower
waters of the Gulf of Mexico. In February 1997, the Company entered a Deepwater
Gulf exploration venture with Conoco encompassing 155,520 gross (57,658 net)
acres located off the coast of Louisiana in water depths ranging from 2,500 to
7,500 feet (the "Deepwater Venture"). In addition, in a federal lease sale
conducted in August 1997, the Company was the high bidder on six blocks located
in Keathley Canyon. If all of the Company's Keathley Canyon bids are awarded,
the Company's holdings in the Deepwater Gulf will increase to 190,080 gross
(92,218 net) acres. The Company has sought and is likely to continue to seek
experienced joint venture partners to pursue opportunities in the Deepwater
Gulf, in part to manage the investment risk of drilling and completing these
deepwater wells. The Company believes that the Deepwater Gulf provides it with
substantial long term reserve and production growth opportunities in the
Company's Gulf of Mexico focus area.

The Company plans to spend a total of approximately $460 million for
capital expenditures in 1997, including the South Pass Alliance. See "-- Recent
Developments." Of this amount, $281 million has been budgeted for drilling
expenditures, of which $107 million is for exploration drilling. The total
capital expenditure budget for 1998 is $325 million, including $154 million for
development drilling and $150 million for exploration drilling (of which $25
million is budgeted for the Deepwater Gulf).

RECENT DEVELOPMENTS

On October 15, 1997, the Company and Shell Offshore, Inc. ("Shell"), one of
the most successful and experienced exploration companies and a leader in
technological advances in the Gulf of Mexico, entered into an exploratory joint
venture agreement (the "Delta Exploration Joint Venture"). The agreement
establishes an Area of Mutual Interest ("AMI") covering approximately 240 square
miles in a coastal and offshore section of the Delta Area. Under the terms of
the agreement, OEI and Shell have each contributed existing leasehold, project
inventory and proprietary 3-D seismic data within the AMI, and the properties
will be operated by OEI. The Company believes that this venture presents
significant opportunities arising from Shell's technical expertise and knowledge
of the area, the Company's own experience with exploration, exploitation and
development techniques on its neighboring Delta Area properties, and the
Company's existing infrastructure and capacity in the area. The Company expects
the venture to spud its initial exploratory well in 1998.

In addition, the Company and Shell entered into an alliance encompassing
two fields in the South Pass area located in the Gulf of Mexico (the "South Pass
Alliance"). As part of the South Pass Alliance, the Company acquired from Shell,
for a purchase price of approximately $60.8 million, a 50% working interest in
various producing federal leases and related processing facilities in South Pass
61 and 65 fields (the "South Pass Properties") and became the operator of the
properties. Strategically situated near the Company's holdings in the Delta
Area, the South Pass Properties include interests in approximately 95 producing
wells located on approximately 26,250 gross acres. Current estimated production
from the newly acquired interests is approximately 3,500 BOE per day net to the
Company. The Company believes that the South Pass Properties have substantial
similarities with its existing Delta Area properties, 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 intends to utilize its experience in operating and successfully
exploiting its existing Delta Area properties to maximize the profitability of
the South Pass Properties.
4
<PAGE> 5

STRENGTHS

The Company believes it has unique strengths that position it to continue
as a successful independent operator in the Gulf of Mexico and coastal onshore
Louisiana, including the following:

Expertise in the Gulf of Mexico. Management believes the Company's existing
asset base and incentivized personnel provide it with competitive advantages for
operating in the Gulf of Mexico. The Company continues to develop its high
quality team of geoscientists and engineers, currently numbering 57, each of
whom has substantial experience in this region largely through tenure at major
oil companies. The Company has also assembled a team of experienced field
personnel, most with over 15 years of service in the Company's core areas.
Management has extensive experience and good working relationships with federal,
state and local regulatory agencies in this region. The Company augments its
technical expertise through its strategic relationships, such as the Deepwater
Venture with Conoco.

Quality of existing operations. The Company's Delta Area and Central Gulf
Area fields were originally developed by major oil companies prior to their
acquisition by the Company, and are among the 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 as evidenced by the Company's current inventory of 665 projects.
Production from these fields has been predominantly from depths shallower than
12,000 feet. While cumulative historical production from these horizons has
exceeded 1.78 billion BOE, the Company believes that potential exists for
additional reserves to be found at these horizons, as well as deeper horizons.
As of September 30, 1997, the Company's properties collectively comprised
458,775 gross acres of leases and seismic options (118,380 of which are held by
production).

Extensive technological database. The Company owns or licenses
approximately 1,700 square miles of 3-D seismic data and over 32,000 linear
miles of 2-D seismic data in and around its core properties. OEI uses
state-of-the-art seismic evaluation technology in its exploration and
development activities in order to reduce risks and lower costs. The seismic
evaluation technology is integrated with subsurface data from over 12,000 wells
to improve the Company's ability to properly define the structural and
stratigraphic features which potentially contain accumulations of hydrocarbons.
The Company's geoscientists and engineers integrate and evaluate this expansive
well and 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.

Efficient operator. The Company is the operator of over 90% of its 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 37%, from $5.45 per BOE for the period
from inception (April 20, 1992) through December 31, 1992 to $3.46 per BOE for
the twelve months ended September 30, 1997. From 1989 to 1991, prior to the
Company's ownership, lease operating expenses for the Delta Area properties
ranged from $6.59 to $11.33 per BOE.

Expandable base of operations. The Company has additional production
capacity available at its facilities located in the Delta Area and the Central
Gulf Area, which can provide a foundation for further acquisition, exploitation
and exploration in the Gulf of Mexico to achieve additional production at low
incremental costs. 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. The Company expects that it will be able
to realize such benefits in connection with the South Pass Alliance, the Delta
Exploration Joint Venture and the Deepwater Venture.
5
<PAGE> 6

BUSINESS STRATEGY

The Company's strategy is to increase shareholder 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 operating its properties more efficiently and
by increasing production. The Company is implementing this strategy by:

Expanding exploration program. The Company is expanding its exploration
program in the Gulf of Mexico which is designed to provide exposure to selected
higher risk, higher potential rate of return prospects. This expansion consists
of increasing exploration in the Delta Area and the Central Gulf Area, where the
Company has historically been active, as well as entering new areas where the
Company believes its experience and relationships create significant
opportunities, such as the Onshore Exploratory Area, the Delta Exploration Joint
Venture and the Deepwater Gulf. The Company currently intends to divide its
drilling budget equally between exploratory and development drilling. The
Company's exploratory drilling expenditures were $32 million in 1996, and are
expected to increase to approximately $107 million in 1997. In order to reduce
exploration risk, the Company will apply state-of-the-art technology to identify
prospects, select well locations with multiple pay objectives where possible and
may sell a portion of a prospect to an industry partner while preferably
remaining as operator.

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. OEI 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 222% to 48,379 BOE for the three months ended
September 30, 1997 from 15,047 BOE for the year ended December 31, 1994. The
Company currently has an inventory of over 485 development and exploitation
projects on its existing properties. In light of these projects, the Company
plans approximately $174 million of development and exploitation drilling
capital expenditures in 1997, up from approximately $82 million in 1996.

Pursuing joint ventures and strategic acquisitions. The Company is
continually evaluating opportunities to acquire or enter into joint ventures
involving producing and exploratory properties which may possess, among others,
one or more of the following characteristics: (i) close proximity to the
Company's existing operations, (ii) potential opportunities to increase reserves
through exploratory drilling and additional recovery or enhancement techniques
or (iii) potential opportunities to reduce expenses through more efficient
operations. Among other opportunities, this strategy has resulted in the
formation of significant strategic relationships with major oil companies,
including the Deepwater Venture, the South Pass Alliance and the Delta
Exploration Joint Venture. While the Company focuses primarily on joint ventures
and acquisitions involving producing and exploratory properties with large
acreage positions, it evaluates a broad range of potential transactions. Company
personnel have substantial training, experience, and an in-depth knowledge of
the Gulf of Mexico's offshore and onshore areas, as well as established
relationships with a number of major and large independent energy companies
operating in this region. These factors, in combination with the utilization of
state-of-the-art geological and engineering technology, assist in identifying
properties that meet the Company's acquisition and joint venture objectives.

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.
6
<PAGE> 7

THE OFFERINGS

Common Stock offered by the
Company:

U.S. Offering............... 2,480,000 shares

International Offering...... 620,000 shares

- ----------

Total.................. 3,100,000 shares

- ----------

Common Stock offered by the
Selling
Stockholders(1):

U.S. Offering............... 400,000 shares

International Offering...... 100,000 shares

- ----------

Total.................. 500,000 shares

- ----------

Common Stock to be outstanding
after the Offerings.............. 22,886,905 shares(2)

Use of Proceeds.................. The net proceeds to the Company from the
Offerings will be used to repay outstanding
indebtedness under its Revolving Credit
Facility, incurred to finance the
acquisition of the South Pass Properties
and a portion of the Company's 1997
exploration, development and production
activities. The Company will not receive
any proceeds from the sale of the shares of
Common Stock offered by the Selling
Stockholders. See "Use of Proceeds."

NYSE Symbol...................... OEI
- ---------------

(1) Excludes 540,000 shares of Common Stock subject to purchase upon exercise by
the Underwriters of their over-allotment option.

(2) Does not include 2,440,554 shares subject to employee stock options, 684,487
of which are presently exercisable.

RISK FACTORS

An investment in the Common Stock involves certain risks that a potential
investor should carefully evaluate prior to making such an investment. See "Risk
Factors."
7
<PAGE> 8

SUMMARY HISTORICAL FINANCIAL AND OPERATING DATA

The summary historical financial data set forth below for the years ended
December 31, 1994, 1995 and 1996 for the Company have been derived from the
audited financial statements and notes thereto contained elsewhere in this
Prospectus. The financial data for the nine months ended September 30, 1996 and
1997 are derived from unaudited financial statements of the Company. The summary
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."

<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS ENDED
DECEMBER 31, SEPTEMBER 30,
---------------------------------------- -------------------------
1994 1995 1996 1996 1997
------------ ----------- ----------- ----------- -----------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS AND OTHER
FINANCIAL DATA:
REVENUES & EXPENSE DATA:
Revenues............................... $ 75,395 $127,970 $188,451 $116,671 $204,396
Direct Operating Expenses.............. 30,324 40,047 47,098 33,641 48,538
General & Administrative Expenses...... 10,351 11,312 16,154 9,947 13,321
Depreciation, Depletion &
Amortization......................... 36,459 54,084 74,652 48,477 83,926
Interest Expense....................... 4,507 17,620 17,954 12,029 21,236
Loss on Production Payment Repurchase
and Refinancing(1)................... 16,681 -- -- -- --
Net Income (Loss) Before Income Tax
Expense (Benefit) and Extraordinary
Item................................. (22,179) 5,210 32,988 12,750 38,483
Income Tax Expense (Benefit)(2)........ -- (4,692) 12,037 5,051 13,731
Income Before Extraordinary Item....... (22,179) 9,902 20,951 7,699 24,752
Extraordinary Loss on Early
Extinguishment of Debt, Net of
Taxes(3)............................. -- -- -- -- 19,301
Net Income (Loss)...................... (22,179) 9,902 20,951 7,699 5,451
Earnings per Common Share Before
Extraordinary Item(4)
Primary.............................. -- $ 0.65 $ 1.07 $ 0.40 $ 1.18
Fully diluted........................ -- 0.65 1.05 0.40 1.17
Earnings per Common Share After
Extraordinary Item(4)
Primary.............................. -- $ 0.65 $ 1.07 $ 0.40 $ 0.26
Fully diluted........................ -- 0.65 1.05 0.40 0.26
OTHER FINANCIAL DATA:
EBITDA(5).............................. $ 35,855 $ 77,645 $129,100 $ 76,389 $144,793
Net Cash Provided By (Used In)
Operating Activities(6).............. (115,485) 58,880 125,989 59,094 110,829
Capital Expenditures (7)............... 74,477 73,652 251,305 237,824 340,750
OPERATING DATA:
Sales Volumes:
Oil (MBbls).......................... 4,286 6,057 7,149 4,917 6,939
Gas (MMcf)........................... 7,234 12,393 18,720 11,672 27,689
MBOE................................. 5,492 8,123 10,269 6,863 11,554
Average Prices(8):
Oil (per Bbl)........................ $ 14.24 $ 17.39 $ 21.58 $ 20.37 $ 19.50
Gas (per MCF)........................ 1.76 1.82 2.79 2.65 2.51
BOE (per BOE)........................ 13.42 15.75 20.10 19.10 17.72
Lease Operating Expenses (per BOE)..... $ 4.29 $ 3.70 $ 3.52 $ 3.63 $ 3.50
</TABLE>

<TABLE>
<CAPTION>
AS OF
SEPTEMBER 30, 1997
----------------------------
HISTORICAL AS ADJUSTED(9)
---------- --------------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Oil and Gas Assets, Net..................................... $612,521 $612,521
Total Assets................................................ 694,975 768,295
Long-Term Debt.............................................. 464,121 359,121
Stockholders' Equity........................................ 112,044 290,364
</TABLE>

8
<PAGE> 9

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

(1) The amount shown for the year ended December 31, 1994 represents primarily
the excess of the purchase price of production payments over the book value
of such 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 December 7, 1994, the date of the Company's
initial public offering (the "Initial Public Offering"), no historical
federal or state income tax expense has been provided for in the financial
statements. In conjunction with the Initial Public Offering, 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) On July 22, 1997, the Company amended the indenture governing its 13 1/2%
Senior Notes due 2004 (the "13 1/2% Notes"), removing the principal
restrictive covenants and repurchased approximately $124.8 million of the
$125 million in original principal amount of the 13 1/2% Notes for
approximately $151.5 million. This purchase resulted in an extraordinary
charge of $19.3 million, net of taxes of $11.6 million. The extraordinary
charge represented the difference between the purchase price and related
expenses and the net carrying value of the 13 1/2% Notes.

(4) 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 Public Offering, as these amounts would not be meaningful or
indicative of the ongoing entity.

(5) Earnings before extraordinary items, interest, taxes, depreciation,
depletion and amortization ("EBITDA"). EBITDA has not been reduced for the
recognition of noncash revenues associated with 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.

(6) Cash flow from operating activities for the year ended December 31, 1994 was
reduced by $123.6 million related to the repurchase of certain production
payments.

(7) Includes $117.6 million in the year ended December 31, 1996 related to the
acquisition of Central Gulf Area properties and $55.9 million in the nine
months ended September 30, 1997 related to the acquisition of additional
properties in the Delta Area.

(8) Excludes results of hedging activities which increased (decreased) revenue
recognized in the 1994, 1995 and 1996 periods by $1.7 million, $(0.5)
million and $(18.7) million, respectively and by $(14.7) million and $(0.1)
million in the nine months ended September 30, 1996 and 1997. Including the
effect of hedging activities, the Company's average oil price per Bbl
received was $14.56, $17.27 and $19.70 in the years ended December 31, 1994,
1995 and 1996, respectively, and the average gas price per Mcf received was
$1.81, $1.84 and $2.50 in the years ended December 31, 1994, 1995 and 1996,
respectively. In the nine months ended September 30, 1996 and 1997, the
Company's average oil price including hedging activities per Bbl received
was $18.46 and $19.48, respectively, and the average gas price per Mcf
received was $2.20 in the nine months ended September 30, 1996. The Company
did not enter into any hedging activities relating to gas during the nine
months ended September 30, 1997.

(9) As adjusted to give effect to the Offerings and the application of the net
proceeds therefrom. See "Use of Proceeds."
9
<PAGE> 10

SUMMARY HISTORICAL RESERVE INFORMATION

The following tables set forth information with respect to the Company's
proved reserves as of December 31, 1996, as estimated by Netherland Sewell,
independent petroleum engineers for the Company, and as of September 30, 1997,
as estimated by the Company. As of December 31, 1996 and September 30, 1997, 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 $4.17 and $2.72 per Mcf of gas and $25.52 and $19.95 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 -- Oil and
Natural Gas Reserves" and Notes 13 and 15 to the Company's consolidated
financial statements.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
PROVED RESERVES(1)
------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Net Proved Reserves:
Oil (MBbls)............................................. 52,197 11,557 63,754
Gas (MMcf).............................................. 144,058 43,550 187,608
MBOE.................................................... 76,207 18,815 95,022
Estimated Future Net Revenues (Before Income Taxes)....... $642,575 $214,563 $857,139
Present Value of Future Net Revenues (Before Income Taxes;
Discounted at 10%)...................................... $537,643 $159,170 $696,813
Standardized Measure of Discounted Future Net Cash
Flows(2)................................................ $563,058
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31, 1996
PROVED RESERVES(3)
----------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NONPRODUCING UNDEVELOPED TOTAL
--------- ------------ ----------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Net Proved Reserves:
Oil (MBbls)............................... 27,029 11,318 12,429 50,776
Gas (MMcf)................................ 56,836 52,738 35,784 145,358
MBOE...................................... 36,490 20,120 18,393 75,003
Estimated Future Net Revenues (Before Income
Taxes).................................... $306,470 $285,671 $289,633 $881,774
Present Value of Future Net Revenues (Before
Income Taxes; Discounted at 10%).......... $295,668 $188,764 $209,083 $693,515
Standardized Measure of Discounted Future
Net Cash Flows(2)......................... $532,492
</TABLE>

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

(1) The reserve information as of September 30, 1997 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 increased by approximately $2.0 million, $2.0 million and
$1.4 million, respectively, representing the effect of hedging transactions
entered into as of September 30, 1997.

(2) The Standardized Measure of Discounted Future Net Cash Flows, which were
prepared by the Company, represents the Present Value of Future Net Revenues
after income taxes discounted at 10%.

(3) 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 $20.5 million, $18.6
million and $12.4 million, respectively, representing the effect of hedging
transactions entered into as of December 31, 1996.
10
<PAGE> 11

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and
Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange
Act"). All statements other than statements of historical facts included in this
Prospectus, including without limitation, statements under "Prospectus Summary,"
"Risk Factors," "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Business" regarding the planned capital
expenditures, increases in oil and gas production, the number of anticipated
wells to be drilled in 1997 and thereafter, the Company's financial position,
business strategy and other plans and objectives for future operations, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct. There are
numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and in projecting future rates of production and timing of
expenditures, including many factors beyond the control of the Company. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact way, and the accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
made by different engineers often vary from one another. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revisions of such estimate and such revisions, if significant, would
change the schedule of any further production and development drilling.
Accordingly, reserve estimates are generally different from the quantities of
oil and natural gas that are ultimately recovered. Additional important factors
that could cause actual results to differ materially from the Company's
expectations are disclosed under "Risk Factors" and elsewhere in this
Prospectus, including without limitation in conjunction with the forward-looking
statements. All written and verbal forward-looking statements attributable to
the Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.

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 Common Stock offered hereby.

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 -- 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

11
<PAGE> 12

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," and
"Business -- 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 strategies are generally
conservative in nature. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Other Matters."

EFFECTS OF LEVERAGE

The Company is highly leveraged, with outstanding long-term indebtedness of
approximately $464 million as of September 30, 1997. 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 indenture (the "9 3/4% Notes Indenture") related to
the Company's 9 3/4% Senior Subordinated Notes due 2006 (the "9 3/4% Notes") and
the indenture (the "8 7/8% Notes Indenture" and, together with the 9 3/4% Notes
Indenture, the "Indentures") related to the Company's 8 7/8% Senior Subordinated
Notes due 2007 (the "8 7/8% Notes") contain 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
"-- Substantial Capital Requirements," and "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Liquidity and Capital
Resources."

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, completing, 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,

12
<PAGE> 13

including title problems, weather conditions, compliance with governmental
requirements and shortages or delays in the delivery of equipment and services.

Through its participation in the Deepwater Venture and its bids for
Keathley Canyon, the Company has acquired a significant property interest in the
Deepwater Gulf, which may be expanded in the future. Exploration, development
and production operations in the Deepwater Gulf involve significant capital
outlays and substantially different skills and techniques than the Company's
other operations, and there can be no assurance that the Company will achieve
results similar to those previously achieved on its existing properties.
Although the Company hopes to benefit from Conoco's expertise in the Deepwater
Venture, there can be no assurance that such benefits will be realized or that,
if realized, they can be successfully applied to the Company's activities in
other areas of the Deepwater Gulf.

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, a portion
of the net proceeds of the Offerings and borrowings under its $250 million
amended and restated senior revolving bank credit facility dated October 15,
1997 (the "Revolving Credit Facility"). The Company believes that, after debt
service, these sources will be sufficient to fund planned capital expenditures
of approximately $132 million for the remainder of 1997 and $325 million for
1998. If 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 and joint venture
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 or joint ventures through the issuance of additional
debt or equity securities, the sale of production payments or otherwise. These
changes in capitalization may significantly affect the risk profile of the
Company. Additionally, significant acquisitions or joint ventures can change the
nature of the operations and business of the Company depending upon the
character of the properties, which may be substantially different in operating
or geologic characteristics or geographic location than existing properties.
While the Company has historically concentrated on joint ventures and
acquisitions involving producing properties with exploration and development
potential located in the Gulf of Mexico, there is no assurance that the Company
would not pursue acquisitions of properties and joint ventures that are
non-producing or located in other geographic regions. Moreover, there can be no
assurance that the Company will be successful in the acquisition of, or joint
ventures related to, 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
only estimates based on reports prepared by Netherland Sewell, as of December
31, 1996, and by the Company, as of September 30, 1997.

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

13
<PAGE> 14

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 -- 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 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 -- 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 December 31, 1996, total
abandonment costs for the Company's properties estimated to be incurred through
2011 were approximately $84.0 million. Estimated abandonment costs have been
included in determining 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

14
<PAGE> 15

terms of the acquisition agreements for certain of the Company's producing
properties, the Company is required to periodically fund restricted cash
accounts as a reserve for abandonment costs on such properties. See
"Business -- 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 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 -- Abandonment Costs," "-- Governmental Regulation" and
"-- Environmental Matters."

DEPENDENCE UPON KEY PERSONNEL

The success of the Company has been and will continue to be highly
dependent on James C. Flores, the Company's founder, Chairman of the Board,
President and Chief Executive Officer, and certain other senior management
personnel. Loss of the services of any such individuals could have a material
adverse effect on the Company's operations. The Company can make no assurance
regarding the future affiliation of such individuals with the Company. See
"Management."

RESTRICTIONS ON PAYMENT OF DIVIDENDS AND DIVIDEND POLICY

The Company does not currently intend to pay regular cash dividends on the
Common Stock. This policy will be reviewed by the Board of Directors of the
Company from time to time in light of, among other things, the Company's
earnings and financial position and limitations imposed by the Company's debt
instruments.

ANTI-TAKEOVER PROVISIONS; PREFERRED STOCK

The Company's Certificate of Incorporation, Bylaws, Indentures and employee
benefit plans contain provisions which may have the effect of delaying,
deferring or preventing a change in control of the Company. For example, the
Company's Certificate of Incorporation and Bylaws provide for, among other
things, a classified Board of Directors, the prohibition of stockholder action
by written consent and the affirmative vote of at least 66 2/3% of all
outstanding shares of Common Stock to approve the removal of directors from
office. The Company's Board of Directors has the authority to issue shares of
Preferred Stock in one or more series and to fix the rights and preferences of
the shares of any such series without stockholder approval. In addition, the
Board of Directors may issue certain rights ("Rights") pursuant to the rights
plan authorized by the Certificate of Incorporation. Any series of Preferred
Stock is likely to be senior to the Common Stock with respect to dividends,
liquidation rights and, possibly, voting. The ability to issue Preferred Stock
or Rights could have the effect of discouraging unsolicited acquisition
proposals. In addition, upon a Change of Control (as defined in the Indentures),
each holder of 9 3/4% Notes or 8 7/8% Notes may require the Company to purchase
all or a portion of such holder's 9 3/4% Notes or 8 7/8% 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. The Company's employee stock
option plans contain provisions that allow for, among others, the acceleration
of

15
<PAGE> 16

vesting or payment of awards granted under such plan in the event of a "change
of control," as defined in such plan. In addition, the Company has entered into
employment agreements with its officers allowing for cash payments under certain
circumstances following a change in control, as defined, of the Company.

USE OF PROCEEDS

The net proceeds to the Company from the Offerings are estimated to be
approximately $178.3 million (including $.7 million received by the Company upon
the exercise of options by two of the Selling Stockholders). The net proceeds
will be used to repay outstanding indebtedness under the Revolving Credit
Facility. As of November 3, 1997, the balance on the Revolving Credit Facility
was approximately $180 million. Of this amount, approximately $61 million was
incurred to finance the acquisition of the South Pass Properties, with the
remainder incurred during 1997 to date in connection with the Company's
exploration, development and production activities (including drilling
expenditures and the acquisition of leasehold and seismic data) and for general
corporate purposes. The indebtedness under the Revolving Credit Facility bore
interest at a weighted average rate of 8.5% at November 3, 1997 and has a final
maturity date of October 31, 2000. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."

The Company will not receive any proceeds from the sale of Common Stock
offered by the Selling Stockholders.

16
<PAGE> 17

CAPITALIZATION

The following table sets forth the consolidated capitalization of the
Company (i) as of September 30, 1997 and (ii) as adjusted to give effect to the
Offerings and the assumed application of the net proceeds therefrom (assuming
net proceeds of $178.3 million). 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>
SEPTEMBER 30, 1997
-----------------------
AS ADJUSTED
FOR THE
ACTUAL OFFERINGS
-------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Long-term debt:
Revolving Credit Facility(1).............................. $105,000 $ --
Senior Notes.............................................. 245 245
8 7/8% Senior Subordinated Notes.......................... 199,668 199,668
9 3/4% Senior Subordinated Notes.......................... 159,208 159,208
-------- --------
Total long-term debt.............................. 464,121 359,121
Stockholders' Equity:
Preferred stock, $.01 par value, 10,000,000 shares
authorized, no shares issued and outstanding, actual,
as adjusted and as further adjusted.................... -- --
Common stock, $.01 par value, 100,000,000 shares
authorized, 19,702,010 shares issued and outstanding,
actual, and 22,868,677 shares as adjusted.............. 197 229
Additional paid-in capital................................ 93,258 271,547
Retained earnings......................................... 18,588 18,588
-------- --------
Total stockholders' equity........................ 112,044 290,364
-------- --------
Total capitalization.............................. $576,165 $649,485
======== ========
</TABLE>

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

(1) Outstanding borrowings under the Revolving Credit Facility were
approximately $180 million at November 3, 1997.

17
<PAGE> 18

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Company's Common Stock trades on the NYSE under the symbol "OEI." The
following table represents the quarterly high and low sales prices for the
Common Stock on the NYSE since March 25, 1996 and, during the prior periods
indicated, the high and low bid quotations in the over-the-counter market as
quoted by the Nasdaq National Market since the shares became publicly traded
(which quotations reflect the inter-dealer prices, without retail mark-up,
mark-down or commission and may not necessarily represent actual transactions).

<TABLE>
<CAPTION>
HIGH LOW
---- ---
<S> <C> <C>
1995
First Quarter............................................. $12 3/8 $ 9 1/4
Second Quarter............................................ 13 3/4 11 1/4
Third Quarter............................................. 12 3/4 10 1/2
Fourth Quarter............................................ 14 1/2 11 1/4
1996
First Quarter............................................. 18 7/8 13 3/4
Second Quarter............................................ 33 3/4 18 1/8
Third Quarter............................................. 41 1/2 28 3/4
Fourth Quarter............................................ 54 3/8 38 3/8
1997
First Quarter............................................. 56 38
Second Quarter............................................ 53 1/8 38 7/8
Third Quarter............................................. 70 1/8 41 1/4
Fourth Quarter (through November 12, 1997)................ 709/16 52 3/4
</TABLE>

The last reported sale price of the Common Stock as reported on the
composite tape for issues listed on the NYSE on November 12, 1997, was $59 7/8
per share. As of September 30, 1997, there were approximately 157 holders of
record of the Common Stock.

The Company does not anticipate paying cash dividends on its Common Stock
in the foreseeable future. The Company expects that it will retain all available
earnings generated by the Company's operations for the development and growth of
its business. Any future determination as to the payment of dividends will be
made at the discretion of the Board of Directors of the Company and will depend
upon the Company's operating results, financial condition, capital requirements,
general business conditions and such other factors as the Board of Directors
deems relevant. The Company's debt instruments include certain restrictions on
the payment of cash dividends on the Common Stock. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources."

18
<PAGE> 19

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The summary historical 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, 1995 and 1996 for the Company have been derived from
the audited financial statements and notes thereto contained elsewhere in this
Prospectus. The financial data for the nine months ended September 30, 1996 and
1997 are derived from unaudited financial statements of the Company. The summary
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."

<TABLE>
<CAPTION>
PERIOD FROM
INCEPTION NINE MONTHS
(APRIL 20, 1992) YEAR ENDED ENDED
THROUGH DECEMBER 31, SEPTEMBER 30,
DECEMBER 31, ----------------------------------------- -------------------
1992 1993 1994 1995 1996 1996 1997
---------------- -------- -------- -------- -------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS AND OTHER
FINANCIAL DATA:
Revenues and Expense Data:
Revenues.................................. $13,279 $ 47,483 $ 75,395 $127,970 $188,451 $116,671 $204,396
Direct Operating Expenses................. 6,687 19,201 30,324 40,047 47,098 33,641 48,538
General and Administrative Expenses....... 385 5,032 10,351 11,312 16,154 9,947 13,321
Depreciation, Depletion and
Amortization............................ 3,420 20,140 36,459 54,084 74,652 48,477 83,926
Interest Expense.......................... 241 1,055 4,507 17,620 17,954 12,029 21,236
Loss on Production Payment Repurchase and
Refinancing(1).......................... -- -- 16,681 -- -- -- --
Net Income (Loss) Before Income Tax
Expense (Benefit) and Extraordinary
Item.................................... 2,584 2,227 (22,179) 5,210 32,988 12,750 38,483
Income Tax Expense (Benefit)(2)........... -- -- -- (4,692) 12,037 5,051 13,731
Income Before Extraordinary Item.......... 2,584 2,227 (22,179) 9,902 20,951 7,699 24,752
Extraordinary Loss on Early Extinguishment
of Debt, Net of Taxes (3)............... -- -- -- -- -- -- 19,301
Net Income (Loss)......................... 2,584 2,227 (22,179) 9,902 20,951 7,699 5,451
Earnings per Common Share Before
Extraordinary Item(4)
Primary................................. -- -- -- $ 0.65 $ 1.07 $ 0.40 $ 1.18
Fully diluted........................... -- -- -- 0.65 1.05 0.40 1.17
Earnings per Common Share After
Extraordinary Item(4)
Primary................................. -- -- -- $ 0.65 $ 1.07 $ 0.40 $ 0.26
Fully diluted........................... -- -- -- 0.65 1.05 0.40 0.26
OTHER FINANCIAL DATA:
EBITDA(5)................................. $ 6,245 $ 23,422 $ 35,855 $ 77,645 $129,100 $ 76,389 $144,793
Net Cash Provided By (Used In) Operating
Activities(6)........................... 38,042 103,112 (115,485) 58,880 125,989 59,094 110,829
Capital Expenditures(7)................... 34,978 123,600 74,477 73,652 251,305 237,824 340,750
OPERATING DATA:
Sales Volumes:
Oil (MBbls)............................. 670 2,850 4,286 6,057 7,149 4,917 6,939
Gas (MMcf).............................. 1,484 3,704 7,234 12,393 18,720 11,672 27,689
MBOE.................................... 917 3,467 5,492 8,123 10,269 6,863 11,554
Average Prices(8):
Oil (per Bbl)........................... $ 16.18 $ 13.82 $ 14.24 $ 17.39 $ 21.58 $ 20.37 $ 19.50
Gas (per MCF)........................... 1.64 1.81 1.76 1.82 2.79 2.65 2.51
BOE (per BOE)........................... 14.48 13.30 13.42 15.75 20.10 19.10 17.72
Lease Operating Expenses (per BOE)........ $ 5.45 $ 4.10 $ 4.29 $ 3.70 $ 3.52 $ 3.63 $ 3.50
</TABLE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
--------------------------------------------------- SEPTEMBER 30,
1992 1993 1994 1995 1996 1997
------- -------- -------- -------- -------- -------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Oil and Gas Assets, Net................................ $30,998 $122,374 $160,311 $179,944 $355,698 $612,521
Total Assets........................................... 36,837 131,613 181,344 215,457 460,710 694,975
Long-Term Debt......................................... -- 13,448 154,039 171,692 284,142 464,121
Deferred Revenue on Production Payments(9)............. 32,347 108,784 -- -- -- --
Stockholders' Equity................................... 349 (825) 9,703 19,976 105,153 112,044
</TABLE>

19
<PAGE> 20

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

(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 Initial Public Offering, no
historical federal or state income tax expense has been provided for in the
financial statements. In conjunction with the Initial Public Offering, 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) On July 22, 1997, the Company amended the indenture governing the 13 1/2%
Notes, removing the principal restrictive covenants and repurchased
approximately $124.8 million of the $125 million in original principal
amount of the 13 1/2% Notes for approximately $151.5 million. This purchase
resulted in an extraordinary charge of $19.3 million, net of taxes of $11.6
million. The extraordinary charge represented the difference between the
purchase price and related expenses and the net carrying value of the
13 1/2% Notes.

(5) EBITDA has not been reduced for the recognition of noncash revenues
associated with 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.

(6) Cash flow from operating activities in 1992 and 1993 includes $36.8 million
and $95.7 million, respectively, from the sale of 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 such production
payments.

(7) Includes $34.3 million in the year ended December 31, 1992 related to the
acquisition of properties in the Delta Area, $115.5 million in the year
ended December 31, 1993 related to the acquisition of additional properties
in the Delta Area, $117.6 million in the year ended December 31, 1996
related to the acquisition of Central Gulf Area Properties and $55.9 million
in the period ended September 30, 1997 related to the acquisition of
additional properties in the Delta Area.

(8) Excludes results of hedging activities which increased (decreased) revenue
recognized in the 1993, 1994, 1995 and 1996 periods by $1.2 million, $1.7
million, $(0.5) million and $(18.7) million, respectively and by $(14.7)
million and $(0.1) million in the nine months ended September 30, 1996 and
1997, respectively. Including the effect of hedging activities, the
Company's average oil price per Bbl received was $14.23, $14.56, $17.27 and
$19.70 in the years ended December 31, 1993, 1994, 1995 and 1996,
respectively, and the average gas price per Mcf received was $1.81, $1.84
and $2.50 in the years ended December 31, 1994, 1995 and 1996, respectively.
In the nine months ended September 30, 1996 and 1997, the Company's average
oil price including hedging activities per Bbl received was $18.46 and
$19.48, respectively, and the average gas price per Mcf received was $2.20
in the nine months ended September 30, 1996. The Company did not enter into
any hedging activities relating to oil during 1992 or relating to gas during
1992, 1993 and in the nine months ended September 30, 1997.

(9) Amounts represent deferred revenues recognized from the sale of production
payments. See Note 4 to the consolidated financial statements of the
Company.

20
<PAGE> 21

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 an independent energy company engaged in the exploration,
development, acquisition and production of crude oil and natural gas with
operations focused primarily in the Eastern and Central Gulf of Mexico and
coastal onshore Louisiana, some of the most prolific oil and gas producing
regions in the United States. As of September 30, 1997, the Company had
estimated proved reserves of approximately 63.8 MMBbls of oil and 187.6 Bcf of
natural gas, or an aggregate of approximately 95.0 MMBOE, with a Present Value
of Future Net Revenues of approximately $696.8 million and a Standardized
Measure of Discounted Future Net Cash Flows of approximately $563.1 million. On
a BOE basis, approximately 67% of the Company's proved reserves on such date
were oil. The majority of the Company's existing proved reserves are
attributable to Company operated wells or leases and approximately 80% of these
reserves were classified as proved developed at September 30, 1997.

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.
On December 7, 1994, the Company purchased an outstanding 12% minority interest
in a portion of the Delta Area (the "Minority Interest"). The amounts for the
year ended December 31, 1994 do not reflect the Minority Interest prior to its
acquisition.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- -------------------
1994 1995 1996 1996 1997
------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
Sales Volumes
Oil (MBbls)
Excess Over Production Payments... 2,771 6,057 7,149 4,917 6,939
Production Payments............... 1,515 -- -- -- --
------- -------- -------- -------- --------
Total Oil Volumes............ 4,286 6,057 7,149 4,917 6,939
======= ======== ======== ======== ========
Gas (MMcf)
Excess Over Production Payments... 3,456 12,393 18,720 11,672 27,689
Production Payments............... 3,778 -- -- -- --
------- -------- -------- -------- --------
Total Gas Volumes............ 7,234 12,393 18,720 11,672 27,689
======= ======== ======== ======== ========
Revenues(1)
Oil
Excess Over Production Payments... $43,106(2) $105,360 $154,284 $100,141 $135,308
Production Payments............... 17,906 -- -- -- --
------- -------- -------- -------- --------
Total Oil Revenues........... $61,012 $105,360 $154,284 $100,141 $135,308
======= ======== ======== ======== ========
Gas
Excess Over Production Payments... $ 6,757 $ 22,581 $ 52,175 $ 30,950 $ 69,397
Production Payments............... 5,951 -- -- -- --
------- -------- -------- -------- --------
Total Gas Revenues........... $12,708 $ 22,581 $ 52,175 $ 30,950 $ 69,397
======= ======== ======== ======== ========
</TABLE>

21
<PAGE> 22
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- -------------------
1994 1995 1996 1996 1997
------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
Average Sales Prices(1)
Oil (per Bbl)
Excess Over Production Payments... $ 15.56(2) $ 17.39 $ 21.58 $ 20.37 $ 19.50
Production Payments............... 11.82 -- -- -- --
Net Average Oil Price............. 14.24 17.39 21.58 20.37 19.50
Gas (per Mcf)
Excess over Production Payments... $ 1.96 $ 1.82 $ 2.79 $ 2.65 $ 2.51
Production Payments............... 1.58 -- -- -- --
Net Average Gas Price............. 1.76 1.82 2.79 2.65 2.51
BOE (per BOE)
Excess over Production Payments... $ 14.90 $ 15.75 $ 20.10 $ 19.10 $ 17.72
Production Payments............... 11.12 -- -- -- --
Net Average Price................. 13.42 15.75 20.10 19.10 17.72
Severance Taxes(3)..................... $ 6,747 $ 10,023 $ 10,906 $ 8,710 $ 8,061
Lease Operating Expenses(3)............ $23,577 $ 30,023 $ 36,192 $ 24,931 $ 40,477
Lease Operating Expenses (per BOE)..... $ 4.29 $ 3.70 $ 3.52 $ 3.63 $ 3.50
</TABLE>

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

(1) Excludes results of hedging activities which increased (decreased) revenue
recognized in the 1994, 1995 and 1996 periods by $1.7 million, $(0.5)
million and $(18.7) million, respectively, and by $(14.7) million and $(0.1)
million in the nine months ended September 30, 1996 and 1997, respectively.
Including the effect of hedging activities, the Company's average oil price
received was $14.56, $17.27 and $19.70 in the years ended December 31, 1994,
1995 and 1996, respectively, and the average gas price received was $1.81,
$1.84 and $2.50 in the years ended December 31, 1994, 1995 and 1996,
respectively. In the nine months ended September 30, 1996 and 1997,
including hedging activities, the Company's average oil price received was
$18.46 and $19.48, respectively, and the average gas price received was
$2.20 in the nine months ended September 30, 1996. No gas volumes were
hedged in the nine months ended September 30, 1997. Plant processing income
(loss) was ($0.1) million, $0.6 million and $0.7 million in the 1994, 1995
and 1996 periods, respectively. Losses relating to plant processing were
$0.2 million for the nine months ended September 30, 1996 and 1997.

(2) Includes sales of 800 MBbls for the year ended December 31, 1994, subject to
a long-term contract at prices averaging $1.29 per Bbl for the eleven months
ended November 30, 1994. See "Business -- Oil and Gas Marketing and Major
Customers."

(3) Volumes delivered under production payments were received by Enron Reserve
Acquisition Corp. 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.

22
<PAGE> 23

RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1997

Revenues. The following table reflects an analysis of differences in the
Company's oil and gas revenues (expressed in thousands of dollars) between the
nine months ending September 30, 1997 and the comparable period in 1996:

<TABLE>
<CAPTION>
NINE MONTHS 1997
COMPARED TO
NINE MONTHS 1996
----------------
<S> <C>
Increase (decrease) in oil and gas revenues resulting
from differences in:
Crude oil and condensate --
Price.................................................. $(6,012)
Production............................................. 41,179
-------
35,167
Natural gas --
Price.................................................. (4,022)
Production............................................. 42,469
-------
38,447
-------
Plant processing and hedging, net......................... 14,111
-------
Increase in oil and gas revenues............................ $87,725
=======
</TABLE>

For the nine months ended September 30, 1997, the Company's total revenues
increased approximately $87.7 million, or 75%, to $204.4 million, from $116.7
million for the comparable period of 1996. Production levels for the nine months
ended September 30, 1997, increased 68%, to 11,554 MBOE from 6,863 MBOE for the
comparable period in 1996. The Company's average sales prices (excluding hedging
activities) for oil and natural gas for the nine months ended September 30,
1997, were $19.50 per Bbl and $2.51 per Mcf versus $20.37 per Bbl and $2.65 per
Mcf in the 1996 period. The increase in revenues was primarily due to the
aforementioned production increases, partially offset by the decreased oil and
gas prices. The increases for the nine months ended September 30, 1997, included
additional production of 3,401 MBOE and related revenues of $58.8 million
associated with the acquisition of certain interests in certain oil and gas
producing fields and related production facilities primarily situated in the
shallow federal waters of the central Gulf of Mexico, offshore Louisiana (the
"Central Gulf Properties") on September 26, 1996.

For the nine months ended September 30, 1997, the Company's total revenues
were further affected by an increase of $14.5 million over the comparable prior
year period relating to hedging activities. 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's average sales prices (including hedging
activities) for oil for the nine months ended September 30, 1997, was $19.48 per
Bbl versus $18.46 per Bbl in the prior year period. The average sales price
(including hedging activities) for gas for the nine months ended September 30,
1996 was $2.20 per Mcf. No gas volumes were hedged in the nine months ended
September 30, 1997.

Lease operating expenses. Lease operating expenses decreased to $3.50 per
BOE for the nine months ended September 30, 1997, from $3.63 per BOE in the
comparable 1996 period. For the nine months ended September 30, 1997, lease
operating expenses were $40.5 million, as compared to $24.9 million in the 1996
period. The increase of $15.6 million in nine month period is partially a result
of fluctuations in operating expenses associated with increased production and
an increase of approximately $10.4 million in the nine months ended September
30, 1997, respectively, relating to lease operating expenses associated with the
acquired Central Gulf Properties. Workover expenses increased by $1.1 million in
the nine months ended September 30, 1997, from the comparable 1996 period.

Severance taxes. The effective severance tax rate as a percentage of oil
and gas revenues (excluding the effect of hedging activities) decreased to 3.9%
for the nine months ended September 30, 1997 from 6.6% in

23
<PAGE> 24

the nine months ended September 30, 1996. This decrease was primarily due to
increased production from new wells on federal leases, including wells located
on the Central Gulf Properties, 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 $1.15 per BOE for the nine months ended September 30, 1997
from $1.45 per BOE in the comparable 1996 period. For the nine months ended
September 30, 1997, general and administrative expenses were $13.3 million, as
compared to $9.9 million in the comparable 1996 period. The increase is
primarily due to costs associated with increased corporate staffing associated
with both an increase in drilling activities and the Company's acquisition of
the Central Gulf Properties, an increase in franchise taxes due to the issuance
of $160 million of the 9 3/4% Notes on September 26, 1996, an increase in
advertising as a result of the Company's name change on June 17, 1997 and an
increase in accrued bonuses in the 1997 period. These increases were partially
offset in the 1997 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 nine months
ended September 30, 1997, depreciation, depletion and amortization ("DD&A")
expense was $83.9 million, as compared to $48.5 million in the comparable 1996
period. On a BOE basis, DD&A for the nine months ended September 30, 1997, was
$7.26 per BOE, respectively, as compared to $7.06 per BOE for the nine months
ended September 30, 1996. These variances can primarily be attributed to (i) the
Company's increased production and related current and future capital costs from
the 1996 and 1997 drilling programs and (ii) the Company's purchase of the
Central Gulf Properties, partially offset by the increase in proved reserves
resulting from such drilling programs and acquisitions.

Interest expense. For the nine months ended September 30, 1997, interest
expense increased to $21.2 million from interest expense of $12.0 million in the
comparable 1996 period. This increase was primarily due to the increased
interest expense of approximately $11.7 million in the nine months ended
September 30, 1997 relating to the 9 3/4% Notes and interest expense of $4.4
million in the 1997 period relating to the 8 7/8% Notes issued on July 2, 1997.
In addition, interest expense increased due to a higher average outstanding
balance on the Revolving Credit Facility. These increases were partially offset
by a decrease in interest expense of $3.2 million in the 1997 period which is
the result of the repurchase of $124.8 million of the $125 million in original
principal amount of the 13 1/2% Notes by the Company on July 22, 1997, and an
increase in the amount of interest capitalized in the 1997 period, which is the
result of increases in the Company's unevaluated assets, including additional
seismic data and acreage.

Income tax expense. For the nine months ended September 30, 1997, the
Company recorded income tax expense of $13.7 million as compared to $5.1 million
in the comparable 1996 period. Income tax expense for the nine months ended
September 30, 1997, was reduced by $0.7 million due to a change in the Company's
estimated deferred tax liability.

Extraordinary loss on early extinguishment of debt. On July 22, 1997, the
Company repurchased approximately $124.8 million of the $125 million in original
principal amount of the 13 1/2% Notes for approximately $151.5 million. This
repurchase resulted in an after tax extraordinary charge of $19.3 million,
representing the difference between the purchase price and the net carrying
value of the 13 1/2% Notes.

Net income. Due to the factors described above, net income before an
extraordinary charge increased to $24.8 million for the nine months ended
September 30, 1997 from $7.7 million for the comparable period in 1996.
Including the effect of the extraordinary charge, the Company recorded net
income of $5.5 million for the nine months ended September 30, 1997.

24
<PAGE> 25

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 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
year ended December 31, 1996, and the comparable 1995 period:

<TABLE>
<CAPTION>
YEAR ENDED
1996
COMPARED TO
YEAR ENDED
1995
-----------
<S> <C>
Increase (decrease) in oil and gas revenues resulting from
differences in:
Crude oil and condensate --
Price.................................................. $ 29,929
Production............................................. 18,995
--------
48,924
Natural gas --
Price.................................................. 18,067
Production............................................. 11,527
--------
29,594
--------
Plant processing and hedging, net......................... (18,037)
--------
Increase in oil and gas revenues............................ $ 60,481
========
</TABLE>

The Company's total revenues increased approximately $60.5 million, or 47%,
to $188.5 million for the year ended December 31, 1996, from $128.0 million for
the comparable period in 1995. Production levels for the year ended December 31,
1996, increased 26% to 10,269 MBOE from 8,123 MBOE for the comparable period in
1995. The Company's average sales prices (excluding hedging activities) for oil
and natural gas for the year ended December 31, 1996 were $21.58 per Bbl and
$2.79 per Mcf versus $17.39 per Bbl and $1.82 per Mcf in the prior period.
Revenues increased by $30.5 million due to the aforementioned production
increases and by $48.0 million as a result of increased oil and gas prices. For
the year ended December 31, 1996, the Company recognized additional production
of 680 MBOE and related revenues of $14.8 million associated with the
acquisition of the Central Gulf Properties.

For the year ended December 31, 1996, the Company's total revenues were
further affected by a $18.2 million decrease in hedging revenues. 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's average sales prices
(including hedging activities) for oil and natural gas for the year ended
December 31, 1996, were $19.70 per Bbl and $2.50 per Mcf versus $17.27 per Bbl
and $1.84 per Mcf in the prior period.

Lease operating expenses. Lease operating expenses decreased to $3.52 per
BOE for the year ended December 31, 1996, from $3.70 per BOE in the comparable
1995 period. This decrease is primarily the result of increased production in
the Company's oil and gas fields, which have substantial fixed operating costs
due to the capital intensive nature of the facilities and the underutilization
of capacity. For the year ended December 31, 1996, total lease operating
expenses were $36.2 million, as compared to $30.0 million in the 1995 period.
This increase primarily results from fluctuations in normal operating expenses,
including operating expenses associated with increased production and an
increase of approximately $2.8 million relating to lease operating expenses of
the newly acquired Central Gulf Properties. In addition, workover expenses for
the year ended December 31, 1996, increased by $1.1 million to $2.5 million, as
compared to $1.4 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 5.3%
in the year ended December 31, 1996, from 7.8% in the comparable 1995 period.
The decrease was primarily due to increased production from new wells on federal

25
<PAGE> 26

leases, including wells located on the Central Gulf Properties, and from state
leases which were exempt from state severance tax under Louisiana's severance
tax abatement program.

General and administrative expenses. For the year ended December 31, 1996,
general and administrative expenses were $16.2 million as compared to $11.3
million in the comparable 1995 period. This increase is primarily due to costs
of increased corporate staffing associated with both an increase in drilling
activities and the Company's acquisition of the Central Gulf Properties,
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. In addition, the Company
expensed $.9 million relating to costs associated with efforts to purchase an
oil and gas property outside of its United States cost center.

Depreciation, depletion, and amortization expense. For the year ended
December 31, 1996, DD&A expense was $74.7 million as compared to $54.1 million
in the comparable 1995 period. On a BOE basis, DD&A for the year ended December
31, 1996, was $7.27 per BOE as compared to $6.66 per BOE for the year ended
December 31, 1995. This variance can primarily be attributed to the Company's
increased production and related current and future capital costs from the 1995
and 1996 drilling programs and the Company's purchase of the Central Gulf
Properties, partially offset by the increase to proved reserves resulting from
the programs and the acquisition.

Interest expense. For the year ended December 31, 1996, interest expense
increased approximately $0.4 million to $18.0 million, from $17.6 million in the
comparable 1995 period. This increase is primarily a result of interest expense
of approximately $4.1 million related to the issuance of the 9 3/4% Notes in
September 1996. The increase was partially offset by the repayment of a portion
of the Company's debt with proceeds from the common stock offering in March 1996
and the issuance of the 9 3/4% Notes. The increase was also partially offset by
increases in the amount of interest capitalized in the 1996 period, as a result
of an increase in the Company's unevaluated assets, including additional acreage
and seismic data.

Income tax expense (benefit). For the year ended December 31, 1996, the
Company recorded income tax expense of $12.0 million, as compared to a $4.7
million benefit in the comparable 1995 period during which the Company realized
a deferred tax asset.

Net income. Due to the factors described above, net income for the year
ended December 31, 1996, increased to $21.0 million, an increase of $11.1
million or 112% from net income of $9.9 million for the comparable 1995 period.

26
<PAGE> 27

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1995

<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 (excluding hedging
activities) for oil and natural gas for the year ended December 31, 1995 were
$17.39 per Bbl and $1.82 per Mcf, respectively, versus $14.24 per Bbl and $1.76
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 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 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. 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'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 versus $14.56 per Bbl
and $1.81 per Mcf in the prior period.

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 was primarily the result
of increased production at the Delta Area, which have substantial fixed
operating costs due to the capital intensive nature of the facilities and the
underutilization of capacity. Total 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 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 believed to be cost effective, and

27
<PAGE> 28

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 was 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 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 13 1/2% Notes and the Revolving Credit Facility. This increase
was partially offset by interest that was capitalized during the year ended
December 31, 1995, of $2.8 million, as compared to $0.1 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 Company's
initial public offering, 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. At December 31, 1995, management believed it was more likely than
not that the deferred tax asset would be realized. As a result, in 1995 the
Company reversed the valuation allowance and recognized a tax benefit of $4.7
million.

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.

28
<PAGE> 29

LIQUIDITY AND CAPITAL RESOURCES

The following summary table reflects comparative cash flows for the Company
for the years ended December 31, 1994, 1995 and 1996, and the nine months ended
September 30, 1996 and 1997:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------- ---------------------
1994 1995 1996 1996 1997
--------- -------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Net cash provided by (used in) operating
activities(1)......................... $(115,485) $ 58,880 $ 125,989 $ 59,094 $ 110,829
Net cash used in investing activities... (46,607) (77,699) (293,132) (211,381) (290,896)
Net cash provided by financing
activities............................ 162,462 18,463 172,689 171,058 181,361
</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 production payments.

For the nine months ended September 30, 1997, net cash provided by
operating activities increased by $51.7 million. This increase relates primarily
to increased revenues, partially offset by increases in lease operating
expenses, general and administrative expenses, interest expense and the
extraordinary loss related to the repurchase of a portion of the 13 1/2% Notes.
In addition, timing differences on certain receivable and payable balances
affect cash provided by operating activities at any period end.

Cash used in investing activities during the nine months ended September
30, 1997, increased to $290.9 million as compared to $211.4 million in the
comparable 1996 period. The increase in the 1997 period is primarily a result of
the Company's acquisition of certain interests in various state leases in the
Main Pass Block 69 field on March 7, 1997, for a net purchase price of
approximately $55.9 million (the "Main Pass Acquisition"), as well as increased
drilling activity and increased seismic and leasehold purchases in the 1997
period, partially offset by the sale of the Company's interest in the South
Marsh Island 269 field which generated cash of $33.5 million in the 1997 period
and the Company's $117.1 million acquisition of the Central Gulf Properties in
the 1996 period.

Financing activities during the nine months ended September 30, 1997,
generated cash of $181.4 million, as compared to $171.1 million in the
comparable 1996 period. The increase in cash during the 1997 period was
primarily a result of a $105 million increase in net borrowings on the Company's
Revolving Credit Facility and the issuance of the 8 7/8% Notes, which generated
cash of $199.7 million. This increase in cash was offset by the repurchase of
$124.8 million of the 13 1/2% Senior Notes in the third quarter of 1997. The
cash generated in the comparable 1996 period was the result of (i) the issuance
of 4.5 million shares of common stock at $14.75 per share on March 19, 1996,
which yielded net proceeds to the Company of approximately $62.2 million and
(ii) the issuance of the 9 3/4% Notes on September 26, 1996, which yielded net
proceeds to the Company of approximately $154 million, partially offset by the
(x) net payment of $32.2 million on the Company's Revolving Credit Facility and
(y) the repayment a $13.0 million note to Shell Offshore, Inc. in the 1996
period.

Net proceeds to the Company from the Offerings are estimated to be
approximately $178.3 million, which will be used to repay outstanding
indebtedness under its Revolving Credit Facility. As of November 3, 1997, the
balance on the Revolving Credit Facility was approximately $180 million. Of this
amount, approximately $61 million was incurred to finance the acquisition of the
South Pass Properties, with the remainder incurred during 1997 to date in
connection with the Company's exploration, development and production activities
and for general corporate purposes.

29
<PAGE> 30

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, 1994, 1995 and 1996 and the nine
months ended September 30, 1996 and 1997 are as follows:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ --------------------
1994 1995 1996 1996 1997
------- ------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Property acquisition costs of evaluated
properties........................... $25,442 $ 624 $ 59,419 $ 78,372 $ 50,657
Property acquisition costs of
unevaluated properties............... 14,736 2,381 69,766 48,892 42,094
Reclass of properties held for
resale............................... -- -- (37,200) -- --
Exploration costs (drilling and
completion).......................... 8,467 12,153 31,767 17,796 66,540
Development costs (drilling and
completion).......................... 21,634 42,443 81,616 60,807 99,322
Abandonment costs...................... 727 236 352 225 230
Geological and geophysical costs....... 1,362 5,953 13,999 10,559 27,804
Capitalized interest and general and
administrative costs................. 660 4,476 9,191 4,670 12,401
Other capital costs.................... 1,449 5,386 22,395 16,503 41,702
------- ------- -------- -------- --------
$74,477 $73,652 $251,305 $237,824 $340,750
======= ======= ======== ======== ========
</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 nine
months ended September 30, 1997, the Company spent $165.9 million on exploration
and development drilling and $27.8 million on 3-D seismic surveys and other
geological and geophysical costs. Included in property acquisition costs in the
nine months ended September 30, 1997, is the $55.9 million net purchase price of
the Main Pass Acquisition. Of the total net purchase price for the Main Pass
Acquisition, approximately $50.5 million was allocated to evaluated properties
and $5.4 million was allocated to unevaluated properties. Included in other
capital costs for the nine months ended September 30, 1997, is $38.6 million,
which relates primarily to capital costs incurred to install and upgrade
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 its East
Bay properties, 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 its Main Pass 69 properties, 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 September 30, 1997, the escrow balances totaled
approximately $8.0 million.

On October 15, 1997, the Company acquired the South Pass Properties from
Shell for a purchase price of approximately $60.8 million. The Company has
acquired a 50% working interest in the fields and has become operator of the
properties. The acquisition includes interests in 95 producing wells located on
approximately 26,250 gross acres. Current estimated production from the newly
acquired interests is approximately 3,500 BOE per day net to the Company. Also
on October 15, 1997, the Company entered into the Delta Exploration Joint
Venture with Shell which establishes an AMI covering approximately 240 square
miles located in coastal and offshore areas of Plaquemines Parish, Louisiana.
Under the terms of the oil and gas exploration agreement, the Company and Shell
have agreed to contribute existing leasehold, project inventory and proprietary
3-D seismic data within the AMI. The Company expects the venture to spud the
initial exploratory well in 1998.

30
<PAGE> 31

In addition to developing its existing reserves, the Company will continue
to attempt to increase its reserve base, production and operating cash flow by
engaging in strategic acquisitions of oil and gas properties. In order to
finance any such 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, including the
financial condition and performance of the Company, as well 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
Indentures (as defined below).

The Company plans to spend approximately $281.0 million for 1997 drilling
activities and an additional $62.3 million for other direct capital expenditures
including lease acquisitions and seismic purchases. In addition, on March 7,
1997, the Company completed the Main Pass Acquisition for a net purchase price
of approximately $55.9 million, and on October 15, 1997 completed the South Pass
Alliance for a purchase price of approximately $60.8 million. The Company plans
to spend approximately $325.0 million for capital expenditures in 1998. The
Company's other primary capital requirements for the remainder of 1997 and early
1998 will be for the payment of interest of approximately of $7.8 million on its
9 3/4% Notes, interest of approximately $8.9 million on its 8 7/8% Notes and
interest on any borrowings the Company may incur under the Revolving Credit
Facility. The Company expects to fund its current debt service obligations with
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 beyond its control, supplemented with existing cash balances and if
necessary, borrowings under the Revolving Credit Facility. The Company expects
that its cash flow from operations, existing cash balances and availability
under the Revolving Credit Facility will be adequate to execute the remainder of
its 1997 and 1998 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, existing
cash balances 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 currently has a borrowing base of $200
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 Revolving Credit Facility
terminates on October 31, 2000, unless the Company requests and is granted a
one-year deferral of such termination.

Under the terms of the Revolving Credit Facility, the Company is required
to comply with certain financial tests, which may reduce the $200.0 million
borrowing base. Currently, the Company does not believe that these financial
tests will reduce the borrowing base. As of November 3, 1997, the Company's
outstanding balance on its Revolving Credit Facility was $182.0 million,
including letters of credit of $2.0 million primarily associated with bonding
for future abandonment obligations. The Company had remaining availability of
$18.0 million under the Revolving Credit Facility as of November 3, 1997.

Effects of leverage. The Company is highly leveraged with outstanding
long-term debt of approximately $464.1 million as of September 30, 1997. 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
Indentures require the Company to meet certain financial tests, and other
restrictions which may limit its 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.

31
<PAGE> 32

The Company is required to make semi-annual interest payments of $7.8
million on its 9 3/4% Notes each April 1 and October 1 through the year 2006 and
semi-annual interest payments of approximately $8.9 million on its 8 7/8% Notes
each January 15 and July 15 through the year 2007, commencing January 15, 1998.
In addition, the Company is required to make quarterly interest payments on the
Revolving Credit Facility based on outstanding borrowings for the quarterly
period. The Company may also, at its discretion, make principal payments on the
Revolving Credit Facility.

Pursuant to the Indentures, the Company may not incur any Indebtedness
other than Permitted Indebtedness (as defined in the Indentures) unless the
Company's Consolidated Fixed Charge Coverage Ratio (as defined in the
Indentures) for the four full fiscal quarters preceding the proposed new
Indebtedness is greater than 2.5 to 1.0 after giving pro forma effect to the
proposed new Indebtedness, the application of the proceeds of such Indebtedness
and other significant transactions during the period.

In accordance with the terms of the Indentures, if the Company disposes of
oil and gas assets, it must apply such proceeds to permanently pay down certain
indebtedness or within a specified time from the date of the asset sale,
purchase additional oil and gas assets. If proceeds not applied as indicated
above exceed $15 million ($20 million with respect to the 8 7/8% Notes), the
Company shall be required to offer to purchase outstanding 9 3/4% Notes and
8 7/8% Notes or other pari passu indebtedness in an amount equal to the
unapplied proceeds. A similar provision exists with respect to the 13 1/2%
Notes, of which only $245,000 in principal amount currently remains outstanding.

The Company believes it is currently in compliance with all covenants
contained in the Indentures and has been in compliance since the issuance of the
13 1/2% Notes, the 9 3/4% Notes and the 8 7/8% Notes.

OTHER MATTERS

Energy swap agreements. The Company engages in futures contracts with
certain of its production through master swap agreements ("Swap Agreements").
The Company considers these futures contracts to be hedging activities and, as
such, monthly settlements on these contracts are reflected in oil and gas sales.
In order to consider these futures contracts as hedges, (i) the Company must
designate the futures contract as a hedge of future production and (ii) the
contract must reduce the Company's exposure to the risk of changes in prices.
Changes in the market value of futures contracts treated as hedges are not
recognized in income until the hedged item is also recognized in income. If the
above criteria are not met, the Company will record the market value of the
contract at the end of each month and recognize a related gain or loss. Proceeds
received or paid relating to terminated contracts or contracts that have been
sold are amortized over the original contract period and reflected in oil and
gas sales.

The Swap Agreements provide for separate contracts tied to the NYMEX light
sweet crude oil and natural gas futures contracts. The Company has contracts
which contain specific contracted prices ("Swaps") that are settled monthly
based on the differences between the contract prices and the average NYMEX
prices for each month applied to the related contract volumes. To the extent the
average NYMEX price exceeds the contract price, the Company pays the spread, and
to the extent the contract price exceeds the average NYMEX price the Company
receives the spread. Under the terms of the Swap Agreements, each counterparty
has extended the Company a $5 million line of credit for use in conjunction with
its hedging activities. As of November 3, 1997, the Company's exposure under all
contracts covered by the Swap Agreements was approximately $4.0 million.

32
<PAGE> 33

As of September 30, 1997, the Company's open forward position on its
outstanding crude oil Swaps was as follows:

<TABLE>
<CAPTION>
AVERAGE
YEAR MBBLS PRICE
---- ----- -------
<S> <C> <C>
1997........................................................ 975 $19.93
1998........................................................ 4,800 $19.80
1999........................................................ 300 $18.55
2000........................................................ 300 $18.55
----- ------
6,375 $19.70
===== ======
</TABLE>

The Company currently has no outstanding natural gas Swaps.

On March 7, 1997, the Company entered into a basis swap for 9,000 barrels
of oil per month for the period April 1997, through July 1997, with a fixed
price of $(0.11) per barrel basis differential between the monthly calendar
average of Platt's Louisiana Light Sweet and Platt's West Texas Intermediate
crude oil prices.

In addition, on April 7, 1997, the Company entered into a field diesel Swap
for 150,000 gallons per month for the month of April 1997, and August 1997
through March 1998, relating to expected future diesel needs. This Swap
obligates the Company to make or receive payments on the last day of each
respective calendar month based on the difference between a specified price of
$0.5425 per gallon and the average of the daily settlement price per gallon for
the respective calendar month Platt's Gulf Coast Pipeline mean high sulfur 2 oil
contract.

As a result of hedging activity under the Swap Agreements, on a BOE basis,
the Company estimates that approximately 20% of its estimated remaining 1997
production that is classified as proved reserves as of September 30, 1997, will
not be subject to price fluctuation for 1997.

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
80% 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 that 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 on its properties
decreased from 2,059,954 Mcf at December 31, 1996, to 658,728 Mcf at September
30, 1997. This decrease is primarily the result of the Company's Main Pass
Acquisition. During the make-up period for the remaining imbalance, the
Company's gas revenues will be adversely affected. The Company recognizes
revenue and imbalance obligations under the sales method of accounting.

33
<PAGE> 34

BUSINESS
GENERAL

The Company's activities have historically been focused primarily in three
geographically distinct areas in the Gulf of Mexico region, consisting of the
Delta Area, the Central Gulf Area, and the Onshore Exploratory Area. Most
recently, the Company has become active in the Deepwater Gulf (water depth over
1,000 feet) areas of the Gulf of Mexico through both its joint venture with
Conoco and its high bid in a recent federal lease sale on six blocks in the
Keathley Canyon.

The Company's largest area of focus is the Delta Area, which is located
primarily in federal and state waters offshore in the Mississippi River deltaic
region, consisting of interests in 8 fields and encompassing 126,974 gross
(110,483 net) acres. The Delta Area contains approximately 467 producing wells
and includes three of the top 20 fields in the Gulf of Mexico based on total
historical production. The Central Gulf Area, which contains approximately 60
producing wells, consists of interests in 10 oil and gas fields and related
production facilities primarily situated in the shallow federal waters of the
central Gulf of Mexico, offshore Louisiana. The Central Gulf Area encompasses
91,748 gross (61,910 net) acres. The Onshore Exploratory Area consists of
leasehold and seismic lease options totaling 51,653 gross (36,459 net) acres.
These 19 offshore fields, together with the Onshore Exploratory Area, provide
significant opportunities to enhance current production and ultimate reserve
recoveries through development and exploratory drilling, recompletions and
infill and horizontal drilling.

As part of an increased emphasis on reserve additions through exploratory
drilling, the Company has begun to focus on the deepwater areas of the Gulf of
Mexico. Based on the magnitude of recent discoveries by other companies, the
Company believes that exploration in the Deepwater Gulf affords it the
opportunity to discover significantly larger potential reserves and to earn a
high rate of return, complementing its lower risk opportunities in the shallower
waters of the Gulf of Mexico. In February 1997, the Company entered the
Deepwater Venture with Conoco encompassing 155,520 gross (57,658 net) acres
located off the coast of Louisiana in water depths ranging from 2,500 to 7,500
feet. In addition, in a federal lease sale conducted in August 1997, the Company
was the high bidder on six blocks located in Keathley Canyon. If all of the
Company's Keathley Canyon bids are awarded, the Company's holdings in the
Deepwater Gulf will increase to 190,080 gross (92,218 net) acres. The Company
has sought and is likely to continue to seek experienced joint venture partners
to pursue opportunities in the Deepwater Gulf, in part to manage the investment
risk of drilling and completing these deepwater wells. The Company believes that
the Deepwater Gulf provides it

34
<PAGE> 35

with substantial long term reserve and production growth opportunities in the
Company's Gulf of Mexico focus area.

RECENT DEVELOPMENTS

On October 15, 1997 the Company and Shell, one of the most successful and
experienced exploration companies and a leader in technological advances in the
Gulf of Mexico, entered into the Delta Exploration Joint Venture. The agreement
establishes an AMI covering approximately 240 square miles in a coastal and
offshore section of the Delta Area. Under the terms of the agreement, OEI and
Shell have each contributed existing leasehold, project inventory and
proprietary 3-D seismic data within the AMI, and the properties will be operated
by OEI. The Company believes that this venture presents significant
opportunities arising from Shell's technical expertise and knowledge of the
area, the Company's own experience with exploration, exploitation and
development techniques on its neighboring Delta Area properties, and the
Company's existing infrastructure and capacity in the area. The Company expects
the venture to spud its initial exploratory well in 1998.

In addition, the Company and Shell entered into the South Pass Alliance,
encompassing two fields in the South Pass area located in the Gulf of Mexico. As
part of the South Pass Alliance, the Company acquired from Shell, for a purchase
price of approximately $60.8 million, a 50% working interest in various
producing federal leases and related processing facilities in South Pass 61 and
65 fields and became the operator of the properties. Strategically situated near
the Company's holdings in the Delta Area, the South Pass Properties include
interests in approximately 95 producing wells located on approximately 26,250
gross acres. Current estimated production from the newly acquired interests is
approximately 3,500 BOE per day net to the Company. The Company believes that
the South Pass Properties have substantial similarities with its existing Delta
Area properties, 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 intends to utilize its
experience in operating and successfully exploiting its existing Delta Area
properties to maximize the profitability of the South Pass Properties.

STRENGTHS

The Company believes it has unique strengths that position it to continue
as a successful independent operator in the Gulf of Mexico and coastal onshore
Louisiana, including the following:

35
<PAGE> 36

horizons, as well as deeper horizons. As of September 30, 1997, the Company's
properties collectively comprised 458,775 gross acres of leases and seismic
options (118,380 of which are held by production).

BUSINESS STRATEGY

36
<PAGE> 37

and exploitation drilling success, the Company has increased its average daily
production by 222% to 48,379 BOE for the three months ended September 30, 1997
from 15,047 BOE for the year ended December 31, 1994. The Company currently has
an inventory of over 485 development and exploitation projects on its existing
properties. In light of these projects, the Company plans approximately $174
million of development and exploitation drilling capital expenditures in 1997,
up from approximately $82 million in 1996.

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 $281.2 million for
1997 and $303.7 million for 1998 to apply towards a portion of the following
projects on its existing properties.

<TABLE>
<CAPTION>
BUDGETED
EXPENDITURES
NUMBER OF ----------------
TYPE OF PROJECT PROJECTS 1997 1998
--------------- --------- ------ ------
<S> <C> <C> <C>
Exploration Drilling............................. 181 $107.3 $150.0
Recompletion/Workovers........................... 221 18.4 14.0
Waterfloods...................................... 6 5.4 3.6
Development Drilling............................. 182 30.9 36.9
Horizontal Drilling.............................. 4 8.0 1.9
"Develocat" Drilling............................. 71 62.1 64.2
Facility Costs................................... N/A 49.1 33.1
--- ------ ------
Total.................................. 665 $281.2 $303.7
=== ====== ======
</TABLE>

The following opportunities are representative of the type of exploration
projects the Company is currently pursuing:

The Main Course Prospect is designed to test an upthrown three-way closure
located in the northern portion of the Eugene Island 51 Field, in the heart of
the producing geopressured Cib Carst trend. These prospective geopressured Cib
Carst sands are correlative to subtle amplitude anomalies on the upthrown side
of a down-to-the-north fault, and are high to, but fault separated from, a
nearby well which encountered pay in the prospective area. The proposed total
depth for the prospect is 14,900 feet.

The Midnight 2 Prospect, located near the mouth of Southwest Pass in the
South Pass 41 Field area, will test the stratigraphic section through the U Sand
to a depth of 12,600 feet. The project is analogous to the Midnight 1 discovery
drilled in 1996, which tested at approximately 21 MMcf per day and is still
producing high gas volumes. Midnight 2 compares favorably with the discovery in
that the key target P6 and U Sands are

37
<PAGE> 38

both delineated by structurally conforming amplitude anomalies. Several
additional wells will be needed to fully develop the area if successful. The
project has been developed behind a recent statics-corrected 3-D data set.

The Upseis Prospect, located in the southern portion of the South Pass 24
Field, is a deeper pool exploratory well that will test a large upthrown
closure. The targeted fault trap has field pays from 7,000 feet to 11,000 feet
but no wells to date have tested the deeper sections. The Company's proprietary
3-D seismic indicates structurally controlled amplitude support in the objective
sand section. The Upseis Prospect has a proposed total depth of 19,500 feet.

The Whale Prospect, located in the South Pass 24 area of the Company's East
Bay complex, is a deeper pool exploratory project which will test a large
three-way closure. The fault closure has trapped over 36 MMBbls of oil and 38
Bcf of gas in 9 shallower pay sands, but has not been crestally tested in the
deeper potential pay horizons. Recent 3-D seismic indicates a large area of
amplitude anomaly, indicating the probable presence of deep sands. The proposed
total depth of the initial test well is 18,500 feet.

PROPERTIES

The information regarding the Company's properties in the following
discussion is as of December 31, 1996, except that the information with respect
to the Deepwater Gulf is as of September 30, 1997. The discussion excludes
information with respect to the South Pass Alliance and the Delta Exploration
Joint Venture.

Mississippi River Delta Area

The Company's Delta Area is comprised of six Company operated
fields -- South Pass 1, South Pass 24, South Pass 27, South Pass 39, Main Pass
69 and Main Pass 138, as well as two non-operated fields -- South Pass 41 and
Main Pass 140. The Delta Area encompasses approximately 75,458 gross leased
acres in state and federal waters situated near the mouth of the Mississippi
River in the Gulf of Mexico. In addition, the Company has interests in
approximately 19,230 gross leased acres in the Chandeleur Sound, Breton Sound
and Main Pass 71/75 areas, where there are currently no productive wells.

At the core of the Delta Area is the East Bay complex. The East Bay complex
is a major oil production facility with daily production capacity for 70 MBbls
of oil, 240 MMcf of gas and 240 MBbls of water. Within the East Bay complex, the
South Pass 24 field, discovered in 1950, has production established from 64
horizons and 268 reservoirs with cumulative production through December 31,
1996, of 321,869 MBbls of oil and 401,924 MMcf of gas. The adjacent South Pass
27 field, discovered in 1954, has production established from 84 horizons and
445 reservoirs with cumulative production through December 31, 1996, of 334,559
MBbls of oil and 798,056 MMcf of gas.

The Company owns an average 96% working interest in these fields, and for
the six months ended December 31, 1996, the Company averaged daily net sales of
20.3 MBbls of oil and 56.1 MMcf of gas from 478 gross productive wells in the
Delta Area.

Central Gulf Area

The Company's Central Gulf Area is comprised of nine Company operated
fields -- Eugene Island 45, Eugene Island 100, Eugene Island 126, Eugene Island
128, Ship Shoal 47, Ship Shoal 64, South Marsh Island 243, Vermilion 215 and
Vermilion 273, as well as one non-operated field -- Vermilion 76. The Central
Gulf Area consists of approximately 76,000 gross leased acres in federal waters
situated in the shallow federal waters of the Central Gulf of Mexico, offshore
Louisiana.

The Company owns an average 45% working interest in these fields, and for
the six months ended December 31, 1996, the Company averaged daily net sales of
4.0 MBbls of oil and 17.4 MMcf of gas from 76 productive wells in the Central
Gulf Area.

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<PAGE> 39

Effective January 3, 1997, the Company sold its interest in the South Marsh
Island 269 field for $37.2 million. The South Marsh Island 269 field consisted
of 27 productive wells located on approximately 11,450 gross leased acres and
had average daily sales net to the Company for the six months ended December 31,
1996 of 0.8 MBbls of oil and 7.4 MMcf of gas. The Company owned an average 20%
working interest in this field.

Onshore Louisiana

During 1996, the Company extended its operations to include several coastal
onshore exploration projects in the Onshore Exploration Area and believes this
region has been underexplored due to its complex geology and lack of 3-D seismic
data. Advances in 3D seismic acquisition techniques over the past few years have
led the Company to purchase seismic and lease options to conduct 3D seismic
surveys 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 has
completed the acquisition of a 70 square mile proprietary 3D seismic survey on
Mallard Bay along with its 50% working interest partners, and plans to commence
drilling operations in 1997. Separately, the Company acquired in 1996 seismic
and lease options covering 14,060 acres in its Lacassine Refuge prospect area
("Lacassine") located approximately 6 miles northwest of Mallard Bay, where it
also expects to begin drilling in 1997.

Deepwater Gulf

As a result of the Company's increased emphasis on reserve additions
through exploratory drilling, the Company has begun to focus on the Deepwater
Gulf. In February 1997, the Company entered the Deepwater Venture with Conoco,
which encompasses 155,520 gross (57,658 net) acres offshore of Louisiana. In
addition, in a federal lease sale conducted in August 1997, the Company was the
high bidder on 6 tracts located in the Keathley Canyon area of the Deepwater
Gulf. If all of the Company's Keathley Canyon bids are awarded, the Company's
holdings in the Deepwater Gulf would increase to 190,080 gross (92,218 net)
acres. The Company believes that the Deepwater Gulf provides it with substantial
reserve and production growth opportunities in the Company's Gulf of Mexico
focus area.

OIL AND NATURAL GAS RESERVES

Presented below are the estimated quantities of proved developed and proved
undeveloped reserves of crude oil and natural gas and the Present Value of
Future Net Revenues (before income taxes) owned by the Company as of September
30, 1997. Information set forth in the following table is based upon reserve
reports of the Company, prepared in accordance with the rules and regulations of
the Commission. In accordance with such rules and regulations, the pre-tax
estimated Future Net Revenues, the pre-tax Present Value of Future Net Revenues
and the after-tax Present Value of Future Net Revenues as prepared by the
Company was increased by approximately $2.0 million, $2.0 million and $1.4
million, respectively, representing the effect of hedging transactions entered
into as of September 30, 1997.

<TABLE>
<CAPTION>
PROVED RESERVES AT SEPTEMBER 30, 1997
-----------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Net Proved Reserves:
Oil (MBbls)................................ 37,562 14,635 11,557 63,754
Gas (MMcf)................................. 86,208 57,850 43,550 187,608
MBOE....................................... 51,930 24,277 18,815 95,022
Estimated Future Net Revenues (Before Income
Taxes)..................................... $455,882 $186,693 $214,563 $857,138
Present Value of Future Net Revenues (Before
Income Taxes; Discounted at 10%)........... $412,543 $125,100 $159,170 $696,813
Standardized Measure of Discounted Future Net
Cash Flows(1).............................. $563,058
</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%.

39
<PAGE> 40

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, 1996. 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. The Company includes as proven reserves future gas production
estimated by Netherland Sewell to be used in the form of fuel gas in its oil and
gas fields. In accordance with such rules and regulations, the pre-tax estimated
future net revenues, the pre-tax present value of future net revenues and the
after-tax present value of future net revenues as prepared by the Company was
decreased by approximately $20.5 million, $18.6 million and $12.4 million,
respectively, representing the effect of hedging transactions entered into as of
December 31, 1996.

<TABLE>
<CAPTION>
PROVED RESERVES AT DECEMBER 31, 1996
--------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Net Proved Reserves:
Oil (MBbls).................................. 27,029 11,318 12,429 50,776
Gas (MMcf)................................... 56,836 52,738 35,784 145,358
MBOE......................................... 36,490 20,120 18,393 75,003
Estimated Future Net Revenues (Before Income
Taxes)....................................... $306,470 $285,671 $289,633 $881,774
Present Value of Future Net Revenues (Before
Income Taxes; Discounted at 10%)............. $295,668 $188,764 $209,083 $693,515
Standardized Measure of Discounted Future Net
Cash Flows(1)................................ $532,492
</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 September 30, 1997 and December 31, 1996 for production from the
Company's properties were $19.95 and $25.52 per Bbl of crude oil and $2.72 and
$4.17 per Mcf of

40
<PAGE> 41

natural gas. 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 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 December 31, 1996:

<TABLE>
<CAPTION>
GROSS NET
----- ---
<S> <C> <C>
Oil......................................................... 481 458
Gas......................................................... 78 61
--- ---
Total Productive Wells............................ 559 519
=== ===
</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, 49 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 December 31,
1996.

<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
---------------- -----------------
GROSS NET GROSS NET
------- ------ ------- -------
<S> <C> <C> <C> <C>
Federal waters.................................... 92,203 53,758 4,994 4,994
State waters and onshore.......................... 44,282 38,747 55,861 45,125
------- ------ ------ ------
Total................................... 136,485 92,505 60,855 50,119
======= ====== ====== ======
</TABLE>

In January 1997, the Company exercised lease options in Cameron Parish,
Louisiana, which increased gross undeveloped acreage by 12,695 acres and net
undeveloped acreage by 6,348 acres. In addition, the Company currently holds
options covering approximately 28,893 gross acres (21,254 net) in Cameron
Parish, Louisiana, and 16,727 gross and net acres in Plaquemines Parish,
Louisiana, which allow the Company to conduct 3-D seismic operations on such
acreage and to subsequently acquire oil and gas leases.

DRILLING ACTIVITIES

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.

41
<PAGE> 42

The following table sets forth the drilling activity of the Company on its
properties for the period ended December 31, 1994, 1995 and 1996.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1994 1995 1996
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive................................. 1 .9 1 1.0 6 5.5
Nonproductive.............................. 1 .9 3 2.0 6 4.6
Development Wells:
Productive................................. 10 8.8 17 17.0 24 23.7
Nonproductive.............................. 1 .4 0 0.0 1 1.0
-- ---- -- ---- -- ----
Total.............................. 13 11.0 21 20.0 37 34.8
== ==== == ==== == ====
</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 years ended December 31, 1994,
1995 and 1996.

<TABLE>
<CAPTION>
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Production:
Oil (MBbls)........................................... 4,286 6,057 7,149
Gas (MMcf)............................................ 7,234 12,393 18,720
MBOE.................................................. 5,492 8,123 10,269
Average Sales Prices (1):
Oil (per Bbl)......................................... $ 14.24 $ 17.39 $ 21.58
Gas (per Mcf)......................................... $ 1.76 $ 1.82 $ 2.79
Per BOE............................................... $ 13.42 $ 15.75 $ 20.10
Average Lease Operating Expenses
(per BOE)............................................. $ 4.29 $ 3.70 $ 3.52
</TABLE>

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

(1) Excludes results of hedging activities. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $14.56,
$17.27 and $19.70 in the years ended December 31, 1994, 1995 and 1996,
respectively, and the average gas price per Mcf received was $1.81, $1.84
and $2.50 in the years ended December 31, 1994, 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 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

42
<PAGE> 43

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 its 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.

Sales to Shell Oil Company, Murphy Oil USA, Inc. and Enron Capital & Trade
Resources Corp. accounted for 54%, 11% and 17%, respectively, of the Company's
oil and gas revenues for the year ended December 31, 1996.

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 may
decline significantly as a result of decreases in product prices, future changes
in federal income tax laws and adverse economic conditions generally affecting
the industry and the country as a whole.

OPERATING HAZARDS AND UNINSURED RISKS

43
<PAGE> 44

EMPLOYEES

As of October 1, 1997, the Company had 367 full-time employees, none of
whom is represented by any labor union. Included in the total were 160 corporate
employees located in the Company's Baton Rouge, Lafayette and New Orleans,
Louisiana offices, as well as 207 employees who work in the Company's operating
areas. 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 81,000 square feet of office space in Lafayette, Louisiana and
approximately 1,800 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 and Morgan City, 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.

Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the
past, the federal government has regulated the wellhead price of natural gas.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was
enacted, which amended the NGPA to remove wellhead price controls on all
domestic natural gas as of 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.

Several major regulatory changes have been implemented by the FERC from
1985 to the present that have had a major impact on natural gas pipeline
operations, services and rates and thus have significantly altered the marketing
and price of natural gas. Commencing in April 1992, the FERC issued Order Nos.
636, 636-A and 636-B (collectively, "Order No. 636"), which, among other things,
require each interstate pipeline company to "restructure" to provide
transportation separate or "unbundled" from the sale of gas and to make
available on an open and nondiscriminatory basis numerous constituent services
(such as gathering services,

44
<PAGE> 45

storage services, firm and interruptible transportation services, and stand-by
sales and gas balancing services) and to adopt a new ratemaking methodology to
determine appropriate rates for those services. To the extent the pipeline
company or its sales affiliate makes gas sales as a merchant in the future, it
does so in direct competition with all other sellers pursuant to private
contracts; however, pipeline companies and their affiliates were not required to
remain "merchants" of gas and several of the interstate pipeline companies have
become "transporters" only. Following the conclusion of individual restructuring
proceedings for each interstate pipeline pursuant to Order No. 636, the FERC has
approved, with modifications, all of the restructuring plans and generally
accepted compliance filings implementing Order No. 636 on every interstate
pipeline as of the end of 1994.

On July 16, 1996, the Court of Appeals for the District of Columbia Circuit
("D.C. Circuit") issued its opinion on review of Order No. 636. The opinion
upheld most elements of Order No. 636 including the unbundling of sales and
transportation services, curtailment of pipeline capacity, implementation of the
capacity release program and the mandatory imposition of straight-fixed-variable
("SFV") rate design for interstate pipeline companies. The D.C. Circuit did
remand certain aspects of Order No. 636 to the FERC for further explanation
including, inter alia, the FERC's decision to exempt pipelines from sharing in
gas supply realignment ("GSR") costs caused by restructuring; FERC's selection
of a twenty-year term matching cap for the right-of-first-refusal mechanism; the
FERC's restriction on the entitlement of no-notice transportation service to
only those customers receiving bundled sales service at the time of
restructuring; and FERC's determination that pipelines should focus on
individual customers, rather than customer classes, in mitigating the effects of
SFV rate design. On February 27, 1997, the FERC issued its order on remand. The
order reaffirmed the holding of Order No. 636 that pipelines should be entitled
to recover 100 percent of their prudently incurred GSR costs. Moreover, since
Order No. 636, few, if any, pipeline customers have been willing, or required,
to commit to twenty-year contracts for existing capacity. Thus, FERC reduced the
contract matching cap for the right-of-first-refusal mechanism to five years. In
light of the varied post-restructuring experience with no-notice service, the
FERC also decided to no longer limit a pipeline's no-notice service to its
bundled sales customers at the time of restructuring. Finally, the FERC
reaffirmed that pipelines should focus on individual customers, rather that
customer classes, in mitigating the effects of SFV rate design. Appeals of
individual pipeline restructuring orders are still pending before the D.C.
Circuit.

On May 31, 1995, the FERC issued a policy statement on how interstate
natural gas pipelines can recover the costs of new pipeline facilities. The
policy statement focused on whether projects would be priced on a rolled-in
basis (rolling in the expansion costs with the existing facilities) or on an
incremental basis (establishing separate cost-of services and separate rates for
the existing and expansion facilities). The policy statement established a
presumption in favor of rolled-in rates when the rate increase to existing
customers from rolling in the new facilities is 5% or less. While this policy
statement affects the Company only indirectly, the new policy should enhance
competition in natural gas markets and facilitate construction of gas supply
laterals. In the policy statement, the FERC contemplated that the resolution of
pricing methodology would take place in individual proceedings based on the
facts and circumstances of the project. The Company cannot predict what action
the FERC will take in the individual proceedings.

In October of 1992 Congress passed the Energy Policy Act of 1992 ("Energy
Policy Act"). The Energy Policy Act deemed petroleum pipeline rates in effect
for the 365-day period ending on the date of enactment of the Energy Policy Act
or that were in effect on the 365th day preceding enactment and had not been
subject to complaint, protest or investigation during the 365-day period to be
just and reasonable under the Interstate Commerce Act. The Energy Policy Act
also provides that complaints against such rates may only be filed under the
following limited circumstances: (i) a substantial change has occurred since
enactment in either the economic circumstances or the nature of the services
which were a basis for the rate; (ii) the complainant was contractually barred
from challenging the rate prior to enactment; or (iii) the rate is unduly
discriminatory or preferential. The Energy Policy Act further required FERC to
issue rules establishing a simplified and generally applicable ratemaking
methodology for petroleum pipelines, and to streamline procedures in petroleum
pipeline proceedings. On October 22, 1993, the FERC responded to the Energy
Policy Act directive by issuing Order No. 561, which adopts a new indexing rate
methodology for petroleum pipelines. Under the new regulations, which were
effective January 1, 1995, petroleum pipelines are able to change their

45
<PAGE> 46

rates within prescribed ceiling levels that are tied to the Producer Price Index
for Finished Goods, minus one percent. Rate increases made pursuant to the index
will be subject to protest, but such protests must show that the portion of the
rate increase resulting from application of the index is substantially in excess
of the pipeline's increase in costs. The new indexing methodology can be applied
to any existing rate, even if the rate is under investigation. If such rate is
subsequently adjusted, the ceiling level established under the index must be
likewise adjusted.

In Order No. 561, FERC said that as a general rule pipelines must utilize
the indexing methodology to change their rates. FERC indicated, however, that it
was retaining cost-of-service ratemaking, market-based rates, and settlement as
alternatives to the indexing approach. A cost-of-service proceeding will be
instituted to determine just and reasonable initial rates for new services. In
addition, a pipeline can also follow a cost-of-service approach when seeking to
increase its rates above index levels for uncontrollable circumstances. A
pipeline can seek to charge market-based rates if it can establish that it lacks
market power. Finally, a pipeline can establish rates pursuant to settlement if
agreed upon by all current shippers.

On May 10, 1996, the D.C. Circuit affirmed Order No. 561. The Court held
that by establishing a general indexing methodology along with limited
exceptions to indexed rates, FERC had reasonably balanced its dual
responsibilities of ensuring just and reasonable rates and streamlining
ratemaking through generally applicable procedures. Because of the novelty and
uncertainty surrounding the indexing methodology, as well as the possibility of
the use of cost-of service ratemaking and market-based rates, the Company is not
able at this time to predict the effects of Order No. 561, 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 oil and 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, 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 an onshore facility, vessel or
pipeline, 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. For tank vessels, including mobile offshore drilling rigs, the OPA
imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10 million depending on
gross tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. For offshore facilities that have a
worst case oil spill potential of more than 1,000 barrels (which includes many
of the Company's offshore producing facilities), certain amendments to the OPA
that were enacted in 1996 provide that the amount of financial responsibility
that must be demonstrated by most facilities range from $10 million in specified
state waters to $35 million in federal OCS waters, with higher amounts, up to
$150 million in certain limited circumstances where the MMS believes such a
level is justified by the risks posed by the quantity or quality of oil that is
handled by the facility. On March 25, 1997, the MMS promulgated a proposed rule
implementing

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<PAGE> 47

these OPA financial responsibility requirements. Under the proposed rule, the
amount of financial responsibility required for a facility would depend on the
"worst case" oil spill discharge volume calculated for the facility. For oil and
gas producers such as the Company operating offshore facilities in OCS waters,
worst case discharge volumes of up to 35,000 barrels will require a financial
responsibility demonstration of $35.0 million, while worst case discharge
volumes in excess of 35,000 barrels will require demonstrations ranging from
$70.0 million to $150.0 million.

The Company believes that it currently has established adequate proof of
financial responsibility for its offshore facilities at no significant increase
in expense over recent prior years. However, the Company cannot predict whether
these financial responsibility requirements under the OPA amendments or proposed
rule will result in the imposition of substantial additional annual costs to the
Company in the future or otherwise materially adversely effect the Company. The
impact, however, 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. OPA also imposes other requirements on facility operators, such as
the preparation of an oil spill contingency plan. The Company has such plans in
place. The failure to comply with ongoing requirements or inadequate cooperation
in a spill event may subject a responsible party to civil or even criminal
liability.

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
is generally 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, 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 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
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.

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<PAGE> 48

CERCLA also authorizes the EPA, and in some cases, third parties to take actions
in response to releases or threats of releases of hazardous substances 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 are 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 or other pollutants 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. As of January 1, 1997,
the Company's federal NPDES permits prohibit the discharge of produced water,
and other substances generated by the oil and gas industry from wells located in
the coastal waters of Louisiana. The Louisiana Department of Environmental
Quality ("LDEQ"), as administrator of the NPDES permits in Louisiana, issued on
December 30, 1996, and reissued on February 28, 1997, an emergency rule to allow
continued discharge of produced waters in the coastal area, subject to a zero
discharge requirement by no later than December 31, 1999 for produced water
being currently discharged into major deltaic passes of the Mississippi River.
On February 24, 1997, LDEQ issued to the Company a compliance order allowing it
to temporarily discharge produced water into Southwest Pass a major deltaic pass
of the Mississippi River. The Company has submitted to LDEQ a compliance plan
for achievement of zero discharge of produced water at its East Bay Central
Facilities by no later than December 31, 1999. Simultaneously, the Company plans
to reformat a portion of its East Bay facilities to allow for discharge of
produced water in the offshore areas, to the extent allowed by its NPDES
permits. Although the costs to reformat Company operations to comply with these
zero discharge mandates under federal or state law may be 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 ESA. Other
statutes which provide protection to animal and plant species and which may
apply to the Company's operations include, but are not necessarily limited to,
the Marine Mammal Protection Act, the Marine Protection, Research 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

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<PAGE> 49

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 operations. Certain of this information must be provided to
employees, state and local government authorities and citizens.

The Company incurred approximately $620,000, $694,000 and $975,000 relating
to environmental compliance during 1994, 1995 and 1996, respectively.

ABANDONMENT COSTS

The Company is responsible for payment of abandonment costs on the oil and
gas properties it operates. As of December 31, 1996, total abandonment costs on
the Company's oil and gas properties estimated to be incurred through the year
2011 were approximately $84.0 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 certain properties in the Delta Area,
the Company entered into two escrow agreements to provide for the future
plugging and abandonment costs of these properties. One 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 other 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 abandonment 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 December 31,
1996, the escrow balances totaled $6.3 million.

In addition, the MMS requires lessees of OCS properties to post bonds to
cover the costs of 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. The Company has posted with the MMS an area wide bond of $3.0 million and
supplemental bonds totaling $39.8 million. 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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<PAGE> 50

MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth certain information concerning the executive
officers of the Company:

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
James C. Flores........................... 38 Chairman of the Board of Directors,
President & Chief Executive Officer
Richard G. Zepernick, Jr. ................ 36 Executive Vice President -- Exploration &
Production and Director
Robert L. Belk............................ 48 Executive Vice President, Chief Financial
Officer, Treasurer & Director
Thomas D. Clark, Jr....................... 56 Director
Charles F. Mitchell, M.D.................. 48 Director
William W. Rucks, IV...................... 40 Director
Milton J. Womack.......................... 70 Director
Robert K. Reeves.......................... 39 Executive Vice
President -- Administration, General
Counsel & Secretary
David J. Morgan........................... 49 Executive Vice President -- Geology
Michael O. Aldridge....................... 39 Vice President -- Corporate Communications
William S. Flores, Jr..................... 40 Vice President -- Operations
Doss R. Bourgeois......................... 40 Vice President -- Production
Clint P. Credeur.......................... 41 Vice President -- Reservoir Engineering
Stephen T. Laperouse...................... 41 Vice President -- Land and Business
Development
Stephen H. Green.......................... 41 Vice President -- Exploration Geology
James H. Painter.......................... 40 Vice President -- Exploitation Geology
Frank D. Willoughby....................... 32 Vice President -- Controller
John V. Flores............................ 31 Vice President & Assistant General Counsel
</TABLE>

The following biographies describe the business experience of the executive
officers of the Company.

James C. Flores has served as Chairman of the Board of the Company since
its inception in 1992 and as Chief Executive Officer since July 1995. Mr. Flores
became President of the Company in 1997. From 1985 to 1992, Mr. Flores served as
Vice President of FloRuxco, Inc., an oil and gas exploration company.

Richard G. Zepernick, Jr. has been with the Company since its inception,
presently serving as Executive Vice President -- Exploration & Production. Mr.
Zepernick became a director of the Company in September 1994. From May 1993
until June 1997, Mr. Zepernick served as Executive Vice President and Chief
Operating Officer. 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.

Robert L. Belk presently serves as Executive Vice President, Chief
Financial Officer & Treasurer. From May 1993 until June 1997, Mr. Belk served as
Senior Vice President, Chief Financial Officer and Treasurer of the Company. Mr.
Belk became a director of the Company in September 1994. Prior to joining the
Company, Mr. Belk worked in public accounting for H.J. Lowe & Company from 1988
to 1993. Mr. Belk is a Certified Public Accountant.

Thomas D. Clark, Jr. is the Dean of the College of Business Administration
at Louisiana State University in Baton Rouge, Louisiana. Prior to his current
position at Louisiana State University, Mr. Clark was employed with the Florida
State University in Tallahassee where he held a variety of positions including
Professor and Chairman of the Department of Information and Management Services
and Director of the Center for Information Systems Research.

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<PAGE> 51

Charles F. Mitchell, M.D. is a 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.

William W. Rucks, IV has served as a Director of the Company since its
inception. Mr. Rucks is a private venture capital investor. He served as
President and Vice Chairman of the Board of Directors from July 1995 until
September 1996 and as President, Chief Executive Officer and a Director of the
Company from its inception in 1992 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.

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.

Robert K. Reeves presently serves as Executive Vice
President -- Administration, General Counsel & Secretary of the Company. From
May 1994 until June 1997, Mr. Reeves served as the Company's Senior Vice
President, General Counsel & Secretary. From November 1993 to May 1994, Mr.
Reeves served as the Company's Vice President & 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.

David J. Morgan presently serves as Executive Vice President -- Geology.
Mr. Morgan joined the Company in 1993 as Vice President Geology and served as a
Senior Vice President from December 1995 until June 1997. 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.

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. 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.

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.

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.

Stephen T. Laperouse presently serves as Vice President -- Land & Business
Development. Mr. Laperouse joined the Company in 1995 as Land Manager. From 1980
until 1995, Mr. Laperouse worked as a landman for Conoco Inc.

Stephen H. Green presently serves as Vice President -- Exploration Geology.
Mr. Green joined the Company in 1995 as Manager of Exploration Geology. From
1988 until 1995, Mr. Green was employed as a geologist with Newfield
Exploration. From 1980 until 1988, Mr. Green was employed as a geologist with
Tenneco Exploration & Production, Inc.

James H. Painter presently serves as Vice President -- Exploitation
Geology. Mr. Painter joined the Company in 1995 as Manager of Exploitation
Geology. Prior to joining the Company, Mr. Painter was employed as a staff
geologist with Forest Oil Company from 1985 until 1995. From 1980 until 1985 Mr.
Painter was an exploration and production geologist with The Superior Oil
Company and Mobil Producing Texas & New Mexico, Inc.

Frank D. Willoughby presently serves as Vice President -- Controller. Mr.
Willoughby joined the Company in 1993 as Manager of Financial Reporting. From
1992 until 1993, Mr. Willoughby was a senior

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<PAGE> 52

financial analyst for Freeport-McMoRan, Inc. From 1990 until 1992, Mr.
Willoughby was a senior accountant for British Petroleum. From 1988 until 1990,
Mr. Willoughby was employed by KPMG Peat Marwick where he obtained a position of
senior auditor. Mr. Willoughby is a Certified Public Accountant.

John V. Flores joined the Company in 1997 and presently serves as Vice
President & Assistant General Counsel. From 1992 to 1997, Mr. Flores was in the
private practice of law.

James C. Flores, William S. Flores, Jr. and John V. Flores are brothers;
there are no other family relationships between any of the executive officers of
the Company.

SELLING STOCKHOLDERS

The shares of Common Stock being offered hereby by the Selling Stockholders
are owned by James C. Flores, Richard G. Zepernick, Jr. and Robert L. Belk, each
of whom is a director of the Company. In addition, Mr. Flores is Chairman of the
Board of Directors, President and Chief Executive Officer, Mr. Zepernick is
Executive Vice President -- Exploration & Production and Mr. Belk is Executive
Vice President, Chief Financial Officer and Treasurer of the Company. Mr. Flores
will sell 433,333 shares of Common Stock in the Offerings. In addition, Mr.
Flores has granted the Underwriters an option for 30 days to purchase up to an
additional 540,000 shares solely to cover over-allotments, if any. Upon
completion of the Offerings, Mr. Flores will beneficially own 4,888,911 shares
of Common Stock (including (i) 200,000 shares subject to presently exercisable
options, and (ii) the right to acquire 1,600,000 shares from another director of
the Company), representing 21.4% of the shares to be outstanding (4,348,911
shares representing 19.0% of the outstanding shares if the Underwriters'
over-allotment option is exercised in full). Mr. Zepernick will sell 50,000
shares of Common Stock in the Offerings, and will beneficially own 221,875
shares of Common Stock (including 221,500 shares subject to presently
exercisable options), representing less than 1% of the shares to be outstanding
upon completion of the Offerings. Mr. Belk will sell 16,667 shares of Common
Stock in the Offerings, and will beneficially own 68,641 shares of Common Stock
(including 66,666 shares subject to presently exercisable options), representing
less than 1% of the shares to be outstanding upon completion of the Offerings.

CERTAIN UNITED STATES FEDERAL TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following is a general summary of certain United States federal income
and estate tax consequences expected to result under current law from the
purchase, ownership and taxable disposition of Common Stock by a person or
entity other than (i) a citizen or resident of the United States, (ii) a
corporation, partnership of other entity created or organized in or under the
laws of the United States or of any state thereof, (iii) an estate, the income
of which is subject to United States federal income taxation regardless of its
source or (iv) a trust whose administration is subject to the primary
supervision of a United States court and which has one or more United States
fiduciaries who have the authority to control all substantial decisions of the
trust (a "Non-U.S. Holder"). This summary does not address all of the United
States federal income and estate tax considerations that may be relevant to a
Non-U.S. Holder in light of its particular circumstances or to Non-U.S. Holders
that may be subject to special treatment under United States federal income tax
laws (such as insurance companies, tax-exempt organizations, financial
institutions, brokers, dealers in securities, and taxpayers that are neither
citizens nor residents of the United States, or that are foreign corporations,
foreign partnerships or foreign estates or trusts as to the United States).
Furthermore, this summary does not discuss any aspects of state, local or
foreign taxation. This summary is based on current provisions of the Internal
Revenue Code of 1986, as amended (the "Code"), Treasury regulations, judicial
opinions, published positions of the United States Internal Revenue Service (the
"IRS") and other applicable authorities, all of which are subject to change,
possibly with retroactive effect. Each prospective purchaser of Common Stock is
advised to consult its tax advisor with respect to the tax consequences of
acquiring, holding and disposing of Common Stock.

DIVIDENDS

Dividends paid to a Non-U.S. Holder of Common Stock generally will be
subject to withholding of United States federal income tax at a 30 percent rate
(or such lower rate as may be specified by an applicable income tax treaty)
unless the dividends are effectively connected with the conduct of a trade or
business of the

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<PAGE> 53

Non-U.S. Holder within the United States, in which case the dividends will be
taxed at ordinary United States federal income tax rates and will not be subject
to the withholding tax described above. If the Non-U.S. Holder is a corporation,
such effectively connected income may also be subject to an additional "branch
profits tax."

SALE OR DISPOSITION OF COMMON STOCK

A Non-U.S. Holder generally will not be subject to United States federal
income tax in respect of any gain recognized on the sale or other taxable
disposition of Common Stock so long as (i) the gain is not effectively connected
with a trade or business of the Non-U.S. Holder in the United States; (ii) in
the case of a Non-U.S. Holder who is an individual and holds the Common Stock as
a capital asset, either (a) such holder is not present in the United States for
183 or more days in the taxable year of the disposition or (b) such holder does
not have a "tax home" in the United States for United States federal income tax
purposes or does not maintain an office or other fixed place of business in the
United States to which such gain is attributable; (iii) the Non-U.S. Holder is
not subject to tax pursuant to the provisions of United States federal income
tax law applicable to certain United States expatriates or (iv) the Common Stock
continues to be "regularly traded on an established securities market" for
United States federal income tax purposes and the Non-U.S. Holder has not held,
directly or indirectly, at any time during the five-year period ending on the
date of disposition (or, if shorter, the Non-U.S. Holder's holding period), more
than 5 percent of the outstanding Common Stock.

BACKUP WITHHOLDING AND INFORMATION REPORTING

United States backup withholding tax generally will not apply to dividends
paid on Common Stock to a Non-U.S. Holder at an address outside the United
States. The Company must report annually to the IRS and to each Non-U.S. Holder
the amount of dividends paid to such holder and the amount, if any, of tax
withheld with respect to such dividends. This information may also be made
available to the tax authorities in the Non-U.S. Holder's country of residence.

Upon the sale or other taxable disposition of Common Stock by a Non-U.S.
Holder to or through a United States office of a broker, the broker must backup
withhold at a rate of 31 percent and report the sale to the IRS, unless the
holder certifies its non-U.S. status under penalties of perjury or otherwise
establishes exemption. Upon the sale or other taxable disposition of Common
Stock by a Non-U.S. Holder to or through the foreign office of a United States
broker, or a foreign broker with certain types of relationships to the United
States, the broker must report the sale to the IRS (but is not required to
backup withhold) unless the broker has documentary evidence in its files that
the seller is a Non-U.S. Holder and certain other conditions are met, or the
holder otherwise establishes an exemption.

Backup withholding is not an additional U.S. federal income tax. Amounts
withheld under the backup withholding rules are generally allowable as a refund
or credit against such Non-U.S. Holder's United States federal income tax
liability, if any, provided that the required information is furnished to the
IRS.

The United States Treasury Department has recently issued regulations
generally effective for payments made after December 31, 1998 that will affect
the procedures to be followed by a Non-U.S. Holder in establishing such holder's
status as a Non-U.S. Holder for purposes of the withholding, backup withholding
and information reporting rules discussed herein. Among other things, a Non-U.S.
Holder may be required to furnish new certification of foreign status.
Prospective investors should consult their advisors concerning the effect of
such regulations on an investment in the Common Stock.

FEDERAL ESTATE TAXES

Common Stock owned or treated as owned by an individual who is not a
citizen or resident (as specially defined for United States federal estate tax
purposes) of the United States at the time of death will be included in such
individual's gross estate for United States federal estate tax purposes, unless
an applicable estate tax treaty provides otherwise.

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<PAGE> 54

UNDERWRITING

Subject to the terms and conditions set forth in the U.S. purchase
agreement (the "U.S. Purchase Agreement") among the Company, the Selling
Stockholders and each of the underwriters named below (the "U.S. Underwriters"),
the Company and the Selling Stockholders have agreed to sell to each of the U.S.
Underwriters, and each of the U.S. Underwriters, for whom Merrill Lynch, Pierce,
Fenner & Smith, Incorporated, Lehman Brothers Inc. (collectively, the co-lead
managers), Howard, Weil, Labouisse, Friedrichs Incorporated, Morgan Stanley &
Co. Incorporated, Petrie Parkman & Co., Inc. and Smith Barney Inc. are acting as
representatives (the "U.S. Representatives"), has severally agreed to purchase,
the number of shares of Common Stock set forth below opposite their respective
names.

<TABLE>
<CAPTION>
NUMBER
UNDERWRITERS OF SHARES
------------ ---------
<S> <C>
Merrill Lynch, Pierce, Fenner & Smith
Incorporated................................... 400,000
Lehman Brothers Inc......................................... 400,000
Howard, Weil, Labouisse, Friedrichs Incorporated............ 400,000
Morgan Stanley & Co. Incorporated........................... 400,000
Petrie Parkman & Co., Inc................................... 400,000
Smith Barney Inc............................................ 400,000
Bear, Stearns & Co. Inc..................................... 120,000
PaineWebber Incorporated.................................... 120,000
Salomon Brothers Inc ....................................... 120,000
Sanders Morris Mundy Inc. .................................. 120,000
---------
Total.......................................... 2,880,000
=========
</TABLE>

The Company and the Selling Stockholders have also entered into an
international purchase agreement (the "International Purchase Agreement") with
certain other underwriters outside the United States and Canada (the
"International Managers" and, together with the U.S. Underwriters, the
"Underwriters"). Subject to the terms and conditions set forth in the
International Purchase Agreement, and concurrently with the sale of 2,880,000
shares of Common Stock to the U.S. Underwriters pursuant to the U.S. Purchase
Agreement, the Company and the Selling Stockholders have agreed to sell to the
International Managers, and the International Managers severally have agreed to
purchase from the Company and the Selling Stockholders, an aggregate of 720,000
shares of Common Stock. The public offering price per share of Common Stock and
the total underwriting discount per share are identical under the U.S. Purchase
Agreement and the International Purchase Agreement.

In the U.S. Purchase Agreement and the International Purchase Agreement,
the several U.S. Underwriters and the several International Managers,
respectively, have agreed, subject to the terms and conditions set forth
therein, to purchase all of the shares of Common Stock being sold pursuant to
each such Purchase Agreement if any of such shares are purchased. Under certain
circumstances, the commitments of non-defaulting U.S. Underwriters or
International Managers (as the case may be) may be increased as set forth in the
U.S. Purchase Agreement and the International Purchase Agreement, respectively.
The closing with respect to the sale of shares of Common Stock to be purchased
by the U.S. Underwriters and the International Managers are conditioned upon one
another.

The U.S. Underwriters and the International Managers have entered into an
intersyndicate agreement (the "Intersyndicate Agreement") that provides for the
coordination of their activities. Under the terms of the Intersyndicate
Agreement, the Underwriters are permitted to sell shares of Common Stock to each
other for the purposes of resale at the public offering price, less an amount
not greater than the selling concession. Under the terms of the Intersyndicate
Agreement, the International Managers and any dealer to whom they sell shares of
Common Stock will not offer to sell or sell shares of Common Stock to persons
who are United States or Canadian persons or to persons they believe intend to
resell to persons who are United States or Canadian persons, and the U.S.
Underwriters and any dealer to whom they sell shares of Common Stock will not
offer to sell or sell shares of Common Stock to persons who are non-United
States and non-Canadian

54
<PAGE> 55

persons or to persons they believe intend to resell to persons who are
non-United States persons or non-Canadian persons, except, in each case, for
transactions pursuant to the Intersyndicate Agreement.

The U.S. Representatives have advised the Company that the U.S.
Underwriters propose to offer the shares of Common Stock offered hereby 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 $1.41 per share. The U.S. Underwriters may allow, and such dealers may
reallow, a discount not in excess of $.10 per share on sales to certain other
dealers. After the U.S. Offering, the public offering price, concession and
discount may be changed.

One of the Selling Stockholders has granted the U.S. Underwriters an
option, exercisable by the U.S. Representatives, to purchase up to 432,000
additional shares of Common Stock at the public offering price set forth on the
cover page of this Prospectus, less the underwriting discount. Such option,
which expires 30 days after the date of this Prospectus, may be exercised solely
to cover over-allotments. To the extent that the U.S. Representatives exercise
such option, each of the U.S. Underwriters will be obligated, subject to certain
conditions, to purchase approximately the same percentage of the option shares
that the number of shares to be purchased initially by that U.S. Underwriter
bears to the total number of shares to be purchased initially by the U.S.
Underwriters. The same Selling Stockholder has also granted an option to the
International Managers, which expires 30 days after the date of this Prospectus,
to purchase up to 108,000 additional shares of Common Stock to cover
over-allotments, if any, on terms similar to those granted to the U.S.
Underwriters.

The Company and the Selling Stockholders have 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.

The Company and its directors, including the Selling Stockholders, have
agreed that they will not, without the prior written consent of Merrill Lynch &
Co., offer, sell or otherwise dispose of, any shares of Common Stock or any
securities convertible into shares of Common Stock, except for or upon the
exercise of currently outstanding options (except for the Offerings and the
over-allotment option granted to the Underwriters in the Offerings), for a
period of 90 days from the date of this Prospectus.

Until the distribution of the Common Stock is completed, rules of the
Commission may limit the ability of the Underwriters and certain selling group
members to bid for and purchase the Common Stock. As an exception to these
rules, the U.S. Representatives are permitted to engage in certain transactions
that stabilize the price of the Common Stock. Such transactions consist of bids
or purchases for the purposes of pegging, fixing or maintaining the price of the
Common Stock.

If the Underwriters create a short position in the Common Stock in
connection with the Offerings, i.e., if they sell more shares of Common Stock
than are set forth on the cover page of this Prospectus, the U.S.
Representatives may reduce that short position by purchasing Common Stock in the
open market. The U.S. Representatives may also elect to reduce any short
position by exercising all or part of the over-allotment option described above.

The U.S. Representatives may also impose a penalty bid on certain
Underwriters and selling group members. This means that if the U.S.
Representatives purchase shares of Common Stock in the open market to reduce the
Underwriters' short position or to stabilize the price of the Common Stock, they
may reclaim the amount of the selling concession from the Underwriters and
selling group members who sold those shares as part of the Offerings.

In general, purchases of a security for the purpose of stabilization or to
reduce a short position could cause the price of the security to be higher than
it might be in the absence of such purchases. The imposition of a penalty bid
might also have an effect on the price of a security to the extent that it were
to discourage resales of the security.

55
<PAGE> 56

Common Stock. In addition, neither the Company nor any of the Underwriters makes
any representation that the U.S. Representatives will engage in such
transactions or that such transactions, once commenced, will not be discontinued
without notice.

MLSI, an affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated,
acts as a specialist in the Common Stock of the Company pursuant to the rules of
the New York Stock Exchange, Inc. Under an exemption granted by the Securities
and Exchange Commission on July 31, 1995, MLSI will be permitted to carry on its
activities as a specialist in the Common Stock for the entire period of the
distribution of the Common Stock. The exemption is subject to the satisfaction
by MLSI of the conditions specified in the exemption.

LEGAL MATTERS

Certain legal matters in connection with the Common Stock 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 financial statements as of December 31, 1996 and 1995 and each of the
three years in the period ended December 31, 1996, 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 herein in reliance on 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, 1994, 1995 and 1996 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.

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.

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/A for the year ended
December 31, 1996;

b. The Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1997;

c. The Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1997;

d. The Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1997; and

e. The description of the Company's Common Stock contained in the
Company's Registration Statement on Form 8-A filed March 8, 1996.

56
<PAGE> 57

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 Offerings 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, OCEAN ENERGY, INC., 8440
JEFFERSON HIGHWAY, SUITE 420, BATON ROUGE, LOUISIANA 70809, (504) 927-1450.

57
<PAGE> 58

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 degrees 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.

"BOE" means barrels of oil equivalent.

"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.

"Develocat Drilling" involves evaluating deeper untested sands classified
as exploratory while developing a shallower known reservoir.

"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.

"Exploration Drilling" 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.

"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.

"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

58
<PAGE> 59

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%.

"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

59
<PAGE> 60

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).

"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.

60
<PAGE> 61

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets as of December 31, 1996 and
1995...................................................... F-3
Consolidated Statements of Operations for the years ended
December 31, 1996, 1995 and 1994.......................... F-4
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 1996, 1995
and 1994.................................................. F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994.......................... F-6
Notes to Consolidated Financial Statements.................. F-7
Consolidated Balance Sheet as of September 30, 1997......... F-26
Consolidated Statements of Operations for the nine months
ended September 30, 1997 and 1996......................... F-27
Consolidated Statements of Cash Flows for the nine months
ended September 30, 1997 and 1996......................... F-28
Notes to Consolidated Financial Statements.................. F-29
</TABLE>

F-1
<PAGE> 62

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of
Ocean Energy, Inc. and subsidiaries:

We have audited the accompanying consolidated balance sheets of Ocean
Energy, Inc. (a Delaware corporation, formerly Flores & Rucks, Inc.) and
subsidiaries, as of December 31, 1996 and 1995 and the related consolidated
statements of operations, stockholders' equity and cash flows for each of the
three years in the period ended December 31, 1996. 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 Ocean Energy, Inc. and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
February 24, 1997

F-2
<PAGE> 63

OCEAN ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1996 1995
------------- -------------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $ 5,758,978 $ 212,238
Joint interest receivables................................ 2,001,605 390,275
Oil and gas sales receivables............................. 33,770,044 17,546,127
Notes and accounts receivable -- stockholders............. -- 129,129
Accounts receivable -- other.............................. 1,500,000 --
Assets held for resale.................................... 37,200,000 --
Prepaid expenses.......................................... 1,213,143 390,412
Other current assets...................................... 2,414,803 424,824
------------- -------------
Total current assets.............................. 83,858,573 19,093,005
Oil and gas properties -- full cost method:
Evaluated................................................. 464,485,367 274,942,435
Less accumulated depreciation, depletion, and
amortization........................................... (188,692,223) (114,040,044)
------------- -------------
275,793,144 160,902,391
Unevaluated properties excluded from amortization......... 79,904,974 19,041,148
Other assets:
Furniture and equipment, less accumulated depreciation of
$2,772,983 and $1,258,225 in 1996 and 1995,
respectively........................................... 4,286,773 2,340,641
Restricted deposits....................................... 6,323,515 4,259,182
Deferred financing costs.................................. 10,543,226 5,127,974
Deferred tax asset........................................ -- 4,692,263
------------- -------------
Total assets...................................... $ 460,710,205 $ 215,456,604
============= =============

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable and accrued liabilities.................. $ 47,718,102 $ 15,090,791
Oil and gas sales payable................................. 7,830,415 5,177,277
Accrued interest.......................................... 5,521,070 2,651,097
Current notes payable..................................... 127,154 --
Deposit on assets held for resale......................... 3,720,000 --
------------- -------------
Total current liabilities......................... 64,916,741 22,919,165
Long-term debt.............................................. 284,141,999 157,391,556
Notes payable to be refinanced under revolving line of
credit.................................................... -- 14,300,000
Deferred hedge revenue...................................... 400,000 870,333
Deferred tax liability...................................... 6,098,144 --
Stockholders' equity:
Preferred stock, $.01 par value; authorized 10,000,000
shares, no shares issued or outstanding at December 31,
1996 and 1995.......................................... -- --
Common stock, $.01 par value; authorized 100,000,000
shares; issued and outstanding 19,640,656 shares and
15,044,125 shares at December 31, 1996 and 1995,
respectively........................................... 196,407 150,441
Paid-in capital........................................... 91,819,465 27,638,465
Retained earnings (deficit)............................... 13,137,449 (7,813,356)
------------- -------------
Total stockholders' equity........................ 105,153,321 19,975,550
------------- -------------
Total liabilities and stockholders' equity........ $ 460,710,205 $ 215,456,604
============= =============
</TABLE>

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

F-3
<PAGE> 64

OCEAN ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
Oil and gas sales............................... $188,451,215 $127,970,126 $ 75,395,112
Operating expenses:
Lease operations.............................. 36,192,253 30,023,426 23,577,089
Severance taxes............................... 10,905,731 10,023,104 6,746,928
Depreciation, depletion and amortization...... 74,652,179 54,083,782 36,459,029
------------ ------------ ------------
Total operating expenses.............. 121,750,163 94,130,312 66,783,046
General and administrative expenses............. 16,153,823 11,312,153 10,350,572
Interest expense................................ 17,954,053 17,620,226 4,507,307
Interest income and other....................... (394,909) (302,597) (748,479
Loss on production payment repurchase and
refinancing................................... -- -- 16,681,211
------------ ------------ ------------
Net income (loss) before income taxes........... 32,988,085 5,210,032 (22,178,545
Income tax expense (benefit).................... 12,037,280 (4,692,263) --
------------ ------------ ------------
Net income (loss)............................... $ 20,950,805 $ 9,902,295 $(22,178,545
============ ============ ============
Earnings per common share
Primary....................................... $ 1.07 $ .65 N.M.
Fully diluted................................. 1.05 .65 N.M.
Weighted average common and common equivalent
share outstanding
Primary....................................... 19,639,942 15,158,514 N.M.
Fully diluted................................. 19,901,461 15,329,740 N.M.
</TABLE>

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

F-4
<PAGE> 65

OCEAN ENERGY, 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, 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
Sale of stock -- public offering.... 45,000 62,146,285 -- 62,191,285
Sale of Stock -- exercise of stock
options.......................... 966 2,034,715 -- 2,035,681
Net income.......................... -- -- 20,950,805 20,950,805
-------- ------------ ------------ ------------
Balance at December 31, 1996.......... $196,407 $ 91,819,465 $ 13,137,449 $105,153,321
======== ============ ============ ============
</TABLE>

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

F-5
<PAGE> 66

OCEAN ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1996 1995 1994
------------- ------------ -------------
<S> <C> <C> <C>
Operating activities:
Net income (loss)............................. $ 20,950,805 $ 9,902,295 $ (22,178,545)
Adjustments to reconcile net income (loss) to
net cash provided by (used in) operating
activities:
Depreciation, depletion and amortization... 76,166,937 54,751,429 36,845,015
Deferred hedge revenue..................... (470,333) 203,666 (565,180)
Deferred tax expense (benefit)............. 10,790,407 (4,692,263) --
Recognition of deferred revenue on sale of
production payment interest.............. -- -- (23,857,212)
Repurchase of production payment interests.... -- -- (107,951,703)
Changes in operating assets and
liabilities:
Accrued interest......................... 1,569,973 1,555,132 1,947,489
Receivables.............................. (19,206,115) (7,055,051) (6,208,990)
Prepaid expenses......................... (822,731) 126,106 --
Other current assets..................... (1,989,979) (352,106) (139,976)
Accounts payable and accrued
liabilities........................... 32,627,311 1,957,344 5,155,926
Oil and gas sales payable................ 2,653,135 2,483,037 1,468,107
Deposit on assets held for resale........ 3,720,000 -- --
------------- ------------ -------------
Net Cash provided by (used in) operating
activities.................................... 125,989,410 58,879,589 (115,485,069)
------------- ------------ -------------
Investing activities:
Additions to oil and gas properties and
furniture and equipment.................... (291,067,648) (75,740,369) (39,408,546)
Increase in restricted deposits............... (2,064,333) (1,958,884) (1,221,377)
Purchase of minority interest................. -- -- (5,977,097)
------------- ------------ -------------
Net cash used in investing activities........... (293,131,981) (77,699,253) (46,607,020)
------------- ------------ -------------
Financing activities:
Sale of stock................................. 64,226,966 369,949 52,806,553
Borrowings on notes payable................... 242,120,000 99,000,020 181,014,776
Payments of notes payable..................... (128,264,402) (81,357,944) (55,632,361)
Deferred financing costs...................... (5,393,253) 451,187 (5,626,787)
Repurchase of common stock.................... -- -- (8,700,000)
Distributions to stockholders................. -- -- (1,400,000)
------------- ------------ -------------
Net cash provided by financing activities....... 172,689,311 18,463,212 162,462,181
------------- ------------ -------------
Increase (decrease) in cash and cash
equivalents................................... 5,546,740 (356,452) 370,092
Cash and cash equivalents, beginning of the
period........................................ 212,238 568,690 198,598
------------- ------------ -------------
Cash and cash equivalents, end of the period.... $ 5,758,978 $ 212,238 $ 568,690
============= ============ =============
Interest paid during the period................. $ 20,896,826 $ 18,288,156 $ 2,808,721
============= ============ =============
</TABLE>

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

F-6
<PAGE> 67

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

Ocean Energy, Inc., formerly 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 Ocean Energy,
Inc., formerly Flores & Rucks, Inc., a Louisiana corporation ("Ocean Louisiana")
and Flores & Rucks LLC ( the "LLC"). Concurrent with the closing of the Initial
Offerings (See Note 2) on December 7, 1994, Ocean 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.

During 1996, the Company issued 4.5 million additional shares of common
stock and $160 million of 9 3/4% Senior Subordinated Notes through public
offerings (See Note 2).

Hereinafter, the "Company" refers to Ocean Energy, Inc., a Delaware
corporation, its predecessors and their respective subsidiaries.

Effective January 1, 1993, Ocean 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 Ocean Louisiana's oil and
gas properties. These two stockholders were deemed co-promoters of Ocean
Louisiana upon the exchange. As no tangible assets, or any assets with
predecessor basis, were acquired by Ocean 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, Ocean 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"). Ocean
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 Ocean
Louisiana, a wholly owned subsidiary and the Subsidiary Guarantor of the
Company. The separate financial statements of Ocean Louisiana are not included
herein because (i) Ocean Louisiana is the only direct active subsidiary of the
Company; (ii) Ocean Louisiana has fully and unconditionally guaranteed the
Senior Notes and the Senior Subordinated Notes (as defined in Note 2); (iii) the
aggregate assets, liabilities, earnings, and equity of Ocean Louisiana are
substantially equivalent to the assets, liabilities, earnings and equity of the
Company on a consolidated basis; and (iv) the presentation of separate financial
statements and other disclosures concerning Ocean 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

F-7
<PAGE> 68

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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 $3,893,000, $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, 1996, 1995 and 1994, respectively. The Company's proportionate
interests in properties held 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 a proved 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 adopted SFAS 121
in 1996. The effect of adopting SFAS 121 did not materially impact the Company's
results of operations or financial position as of December 31, 1996.

Furniture and Equipment

Depreciation is computed using the straight-line method over the estimated
useful lives of the assets, which range from 3 to 5 years.

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 $642,663 and $20,000 for the
years ended December 31, 1996 and 1995, respectively, 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 during the
year ended December 31, 1994, on gas volumes sold in excess of its entitled
share of production. As of December 31, 1996, the Company is in a net
overdelivered position of 2,059,954 Mcf, which will reduce future oil and gas
revenue as the underdelivered parties recoup their share of production. In
connection with acquisitions, under the sales method the Company records a gas
balancing liability only to the extent any net gas imbalance acquired exceeds
the reserves acquired.

F-8
<PAGE> 69

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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).

Statements of Cash Flows

The Company considers all highly liquid investments with a maturity of six
months or less when purchased to be cash equivalents.

Earnings Per Common Share

Primary and fully diluted earnings per common share are based on the
weighted average number of shares of common stock outstanding for the periods,
including common equivalent shares which reflect the dilutive effect of stock
options granted to certain employees and outside directors on various dates
through December 31, 1996. Dilutive options that are issued during a period or
that expire or are canceled during a period are reflected in both primary and
fully diluted earnings per share computations for the time they were outstanding
during the periods being reported.

Earnings per common share has not been presented for the Company for the
year ended December 31, 1994, as this amount 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 $10,543,226, net of accumulated amortization of $1,423,572,
recorded as deferred financing costs as of December 31, 1996, which is related
to the sale of the Senior Notes and the sale of the Senior Subordinated Notes
(See Note 2) and the senior revolving bank credit facility (the "Revolving
Credit Facility"). 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 approximate book value at December 31, 1996. 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.

In addition, prior year oil and gas reserve quantity information in Note 15
has been restated to include estimated future reserves expected to be consumed
by the Company as fuel gas.

2. INITIAL AND SUBSEQUENT 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 the LLC was merged into the Company.
Also, concurrent with the closing of the Initial Offerings, the Company acquired
the production payment obligations for East Bay Complex and Main Pass 69 (See

F-9
<PAGE> 70

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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 Revolving
Credit Facility.

On September 26, 1996, the Company completed an offering of $160,000,000 of
9 3/4% Senior Subordinated Notes at a discount (the "Senior Subordinated Notes")
for proceeds of $159,120,000 (before offering costs). The principal is due
October 1, 2006. Interest on the notes will be payable semi-annually in arrears
on April 1 and October 1 of each year, commencing April 1, 1997. Net proceeds to
the Company were approximately $154 million, which was used primarily to
complete the acquisition of the Central Gulf Properties (See Note 3) and to
repay outstanding indebtedness of $25.1 million under the Company's Revolving
Credit Facility.

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 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 a 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, the Minority Interest's 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, notes payable on JEDI loans (as
defined in Note 9) 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.

On September 26, 1996, the Company acquired from Mobil Oil and Producing
Southeast, Inc. ("Mobil"), certain interests in eleven oil and gas producing
fields and related production facilities primarily situated in the shallow
federal waters of the central Gulf of Mexico, offshore Louisiana, (the "Central
Gulf Properties") for approximately $117.6 million. The Company financed the
acquisition with proceeds from the issuance of the Senior Subordinated Notes
(See Note 2). At December 31, 1996, one of the eleven Central Gulf Properties
was reclassified as "Assets held for resale". The subject property was sold on
January 3, 1997, for $37.2 million. No gain or loss was recognized on the sale.

F-10
<PAGE> 71

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following pro forma information gives effect to the acquisition of the
Central Gulf Properties by the Company as if it had occurred on January 1, 1995.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1996 1995
------------ ------------
(UNAUDITED)
<S> <C> <C>
Total revenues.......................................... $216,528,093 $168,829,040
Net income.............................................. 24,854,741 13,840,044
Earnings per common share...............................
Primary............................................... $ 1.27 $ 0.91
Fully diluted......................................... 1.25 0.90
</TABLE>

The following table discloses certain financial data relative to the
Company's oil and gas producing activities, all of which are located in the
offshore waters of the continental United States.

<TABLE>
<CAPTION>
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
Costs incurred during period:
Capitalized
Purchase of producing properties...... $ 59,419,082 $ 624,097 $ 25,441,295
Purchase of unevaluated properties.... 69,765,719 2,381,227 14,736,334
Properties held for resale............ (37,200,000) -- --
Exploration costs..................... 45,765,965 18,106,000 9,829,000
Development costs, including
capitalized workovers............... 104,010,914 47,829,175 23,083,108
Plugging and abandonment costs........ 352,043 236,000 727,370
Capitalized interest on unevaluated
properties and capitalized general
and administrative costs............ 9,191,313 4,475,979 659,552
------------ ------------ ------------
$251,305,036 $ 73,652,478 $ 74,476,659
============ ============ ============
Charged to expense
Operating costs:
Recurring lease operating expenses.... $ 33,709,222 $ 28,648,019 $ 22,709,507
Major maintenance expenses............ 2,483,031 1,375,407 867,582
------------ ------------ ------------
Total operating costs............ $ 36,192,253 $ 30,023,426 $ 23,577,089
============ ============ ============
Severance taxes....................... $ 10,905,731 $ 10,023,104 $ 6,746,928
============ ============ ============
Oil and gas properties:
Balance, beginning of period............. $293,983,583 $220,331,105 $145,934,272
Additions................................ 287,606,758 73,652,478 74,396,833
Properties held for resale............... (37,200,000) -- --
------------ ------------ ------------
Balance, end of period................... $544,390,341 $293,983,583 $220,331,105
============ ============ ============
Accumulated depreciation, depletion and
amortization:
Balance, beginning of period............. $114,040,044 $ 60,019,583 $ 23,560,554
Provision for depreciation, depletion and
amortization.......................... 74,652,179 54,020,461 36,459,029
------------ ------------ ------------
Balance, end of period................... 188,692,223 114,040,044 60,019,583
------------ ------------ ------------
Net capitalized costs................. $355,698,118 $179,943,539 $160,311,522
============ ============ ============
</TABLE>

F-11
<PAGE> 72

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table discloses financial data associated with capitalized
unevaluated costs as of December 31, 1996.

<TABLE>
<CAPTION>
COSTS INCURRED DURING THE
BALANCE AT YEARS ENDED DECEMBER 31,
DECEMBER 31, -------------------------------------
1996 1996 1995 1994
------------ ----------- ---------- ----------
<S> <C> <C> <C> <C>
Acquisition costs.................. $54,710,827 $45,864,414 $2,232,685 $6,613,728
Exploration costs.................. 18,196,979 13,267,654 4,929,325 --
Development costs.................. 2,291,218 2,291,218 -- --
Capitalized interest............... 4,705,950 3,478,046 1,170,301 57,603
----------- ----------- ---------- ----------
$79,904,974 $64,901,332 $8,332,311 $6,671,331
=========== =========== ========== ==========
</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. In December 1994 Enron contributed its
Enron Option and $1,000 in 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.

F-12
<PAGE> 73

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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,
1996 and 1995, the escrow balances were approximately $6.3 million and $4.3
million, respectively.

6. INCOME TAXES

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.

The Company has adopted Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 requires deferred tax
liabilities or assets be recognized for the anticipated future tax effects of
temporary differences that arise as a result of the difference in the carrying
amounts and the tax bases of assets and liabilities. The components of the
income tax provision (benefit) for each of the periods presented are as follows:

<TABLE>
<CAPTION>
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Current....................................... $ -- $ -- $ --
Deferred...................................... 12,037,280 (4,692,263) --
----------- ----------- -----------
Total............................... $12,037,280 $(4,692,263) $ --
=========== =========== ===========
</TABLE>

Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The tax
effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:

<TABLE>
<CAPTION>
1996 1995 1994
------------ ---------- -----------
<S> <C> <C> <C>
Net operating loss carryforward............... $ 11,271,173 $3,849,463 $ 6,019,935
Temporary differences:
Oil and gas properties...................... (17,369,317) 1,734,991 (1,598,426)
Other....................................... -- (892,191) 1,882,490
------------ ---------- -----------
Total deferred tax (liability) asset.......... (6,098,144) 4,692,263 6,303,999
Valuation allowance........................... -- -- (6,303,999)
------------ ---------- -----------
Net deferred tax (liability) asset............ $ (6,098,144) $4,692,263 $ --
============ ========== ===========
</TABLE>

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-13
<PAGE> 74

OCEAN ENERGY, 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 estimates, management believed it was more likely than
not that the deferred tax asset as of December 31, 1995 would be realized, and
thus eliminated the valuation allowance in 1995.

The principal reasons for the differences between income taxes computed at
the statutory federal income tax rate and the income tax provision (benefit) are
as follows:

<TABLE>
<CAPTION>
1996 1995 1994
-------------------- -------------------- --------------------
% OF % OF % OF
NET NET NET
INCOME INCOME INCOME
BEFORE BEFORE BEFORE
AMOUNT TAXES AMOUNT TAXES AMOUNT TAXES
----------- ------ ----------- ------ ----------- ------
<S> <C> <C> <C> <C> <C> <C>
Income tax expense (benefit) computed at the
statutory federal income tax rate............... $11,545,830 35 $ 1,823,511 35 $(7,762,491) (35)
Increase 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, net........................................ 491,450 1 (211,775) (4) 565,636 2
----------- --- ----------- ---- ----------- ---
Income tax provision (benefit).................... $12,037,280 36 $(4,692,263) (90) $ -- --
=========== === =========== ==== =========== ===
</TABLE>

At December 31, 1996, the Company had regular tax net operating loss
carryforwards of approximately $29.0 million and alternative minimum tax net
operating loss carryforwards of approximately $12.6 million. These loss
carryforward amounts will expire during the years 2009 through 2111.

7. STOCKHOLDERS' EQUITY

In February 1994, the Company agreed to reacquire 1,000 shares of stock
from a former stockholder discussed in Note 1, for a total of $10.0 million (two
notes in the amount of $5 million each). The notes bore interest at 8% and were
paid on March 1, 1995. In June 1994, the Company agreed to reacquire 1,000
shares of stock from the other former stockholder discussed in Note 1 for $8.7
million, $5.0 million of which was paid in June 1994, and the remainder of which
was paid with the proceeds of the Initial Offerings.

8. RELATED PARTY TRANSACTIONS

Effective July 1, 1994, the Company acquired indirectly from stockholders
various overriding royalty interests for $1.2 million.

During 1994, the Company forgave $500,000 due from two stockholders. The
amounts related to promissory notes which bore interest at 8% per annum and were
due upon demand, and if no demand, then by December 31, 1994. 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 1994, the Company contracted with oilfield service companies
previously owned by current and former stockholders. The total amounts paid for
these services was $1,091,152 during the first six months of

F-14
<PAGE> 75

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

During 1994, the Company was assigned an oil and gas prospect from an
officer of the Company, 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 1996, the Company purchased a working interest ownership in a
field where the Company had an existing working interest from the officer for
$188,026.

During 1996, 1995 and 1994, the Company paid $1,430,089, $1,041,088 and
$635,960, 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 owned by the affiliate. These amounts are included in
accounts receivable from stockholders at December 31, 1995 and 1994, and were
repaid in full on March 27, 1996.

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 were payable monthly, with the balance due on
February 10, 1997. The outstanding principal balance plus accrued interest at
December 31, 1996, was $92,133. On February 10, 1997, the balance of the loan
was paid in full. In addition, Union Planters Bank is a member of the syndicate
under the Revolving Credit Facility. Effective December 31, 1996, Mr. Flores
resigned as a member of the Board of Directors of Union Planters Bank.

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
original term of this agreement expired on October 31, 1996, and the term was
extended for a one year period. 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. In 1996, the Company paid $110,565 relating to the agreement.

On September 13, 1996, the Company entered into a retainer agreement for
legal services to be rendered by a law firm owned by a party related to an
officer of the Company. This agreement is automatically extended for successive
3 month periods unless terminated by one of the parties. Legal fees paid by the
Company relating to this retainer during 1996 totaled $25,196.

F-15
<PAGE> 76

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. LONG-TERM DEBT

Long-term debt consisted of the following at:

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1996 1995
------------ -----------
<S> <C> <C>
Note payable to Shell, including accrued interest of
$2,183,735 in 1995, with interest payable at a rate of
6% per annum principal and interest paid March 29, 1996,
collateralized by the vendor's lien and privilege
retained by Shell which was subordinate to the Revolving
Credit Facility......................................... $ -- $15,183,735
$50,000,000 revolving line of credit with a bank, bearing
interest as described below, collateralized by first
mortgage on the Main Pass and East Bay properties....... -- 32,200,000
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
$160,000,000 Senior subordinated unsecured notes bearing
interest at 9 3/4% payable semi-annually on April 1 and
October 1 of each year, commencing April 1, 1997, due
October 1, 2006, issued at a discount for proceeds of
$159,120,000............................................ 159,141,999 --
Promissory note to Union Planters Bank bearing interest at
Wall Street Prime due February 10, 1997, collateralized
by a Company owned seaplane............................. 91,492 106,478
Capital lease from Green Tree Vendor Services Corp. due
August 1997, collateralized by certain computer
equipment............................................... 35,662 85,078
------------ -----------
Total debt...................................... 284,269,153 172,575,291
Less: Current portion........................... 127,154 883,735
------------ -----------
Total long-term debt............................ $284,141,999 $171,691,556
============ ===========
</TABLE>

The Revolving Credit Facility was committed for up to a five-year period.
The Revolving Credit Facility had an initial borrowing base of $50 million. The
Chase Manhattan Bank (the "Agent"), with the concurrence of majority lenders (as
defined in the $50,000,000 Credit Agreement among Flores & Rucks, Inc. and The
Chase Manhattan Bank) (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, 1998, unless the
Company requests and is granted a one-year deferral of such reductions. In
addition, the borrowing base may be reduced if the Company sells a portion of
its oil and gas properties. As of December 31, 1996, the borrowing base under
the Revolving Credit Facility remained at $50 million.

As of February 24, 1997, the Company was in the process of amending and
restating its Revolving Credit Facility and had obtained commitments from all
lenders which will increase the facility size to $150 million and the borrowing
base to $100 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 $25 million exceeds 110% of all
indenture indebtedness (as defined in the Credit Agreement), excluding
subordinated indebtedness. 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

F-16
<PAGE> 77

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1996, the Company's outstanding
balance was $2.0 million, all of which represented letters of credit, primarily
associated with bonding for future abandonment obligations, and thus the Company
had remaining availability of $48.0 million.

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.

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 Indentures relating to the Senior Notes and the Senior Subordinated
Notes contain certain covenants, including, with 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 sale/leaseback transactions; (v)
limitation on transactions with affiliates; (vi) limitation on liens; (vii)
disposition of proceeds of asset sales; (viii) limitation on dividends and other
payment restrictions affecting subsidiaries; and (ix) limitation of mergers,
consolidations and transfers of assets. In addition, the Indenture related to
the Senior Notes includes a covenant with respect to maintenance of adjusted
consolidated net tangible assets, as defined.

Aggregate minimum principal payments for debt and the capital lease at
December 31, 1996, for the next five years are as follows:

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.

10. EMPLOYEE BENEFIT PLANS

The Company has a 401(k) plan which covers all employees. The Company's
contributions to the plan during 1996, 1995 and 1994 were $521,619, $513,690 and
$432,202, respectively.

F-17
<PAGE> 78

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Stock-Based Compensation Plans

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 "APB Opinion No. 25" method whereby no
compensation cost is recognized upon grant if certain requirements are met. The
Company is continuing to account for its stock-based compensation plans under
APB Opinion No. 25. However, proforma disclosures as if the Company adopted the
cost recognition requirements under SFAS 123 are presented below.

Had compensation for the Company's 1996 and 1995 grants for stock-based
compensation plans been determined consistent with SFAS 123, the Company's net
income and earnings per common share for the years ended December 31, 1996 and
1995 would have approximated the proforma amounts below:

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------
1996 1995
-------------------------- -------------------------
AS REPORTED PROFORMA AS REPORTED 1995
----------- ----------- ----------- ----------
<S> <C> <C> <C> <C>
Net income...................... $20,950,805 19,544,426 $9,902,295 $9,779,272
Earnings per common share
Primary....................... $ 1.07 1.00 $ .65 $ .65
Fully Diluted................. 1.05 0.98 .65 .64
</TABLE>

The effects of applying SFAS 123 in this proforma disclosure are not
indicative of future amounts. SFAS 123 does not apply to grants prior to 1995,
and additional awards in the future are anticipated.

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. In 1995, the Board of Directors also
adopted and the stockholders approved a long-term incentive plan for
non-executive employees. This plan has an evergreen provision which replenishes
options available for grant to 300,000 on January 1 of each year. In 1996,
pending approval of the stockholders at the Annual Meeting, the Board of
Directors adopted a plan which provides for not more than 1,000,000 shares of
common stock to be issued to employees 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. A
summary of the Company's stock options under both plans as of December 31, 1996
and 1995 and changes during the years ended on those dates is presented below:

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------------------
1996 1995
------------------------ ------------------------
NUMBER OF WGTD. AVG. NUMBER OF WGTD. AVG.
OPTIONS EXER. PRICE OPTIONS EXER. PRICE
--------- ----------- --------- -----------
<S> <C> <C> <C> <C>
Outstanding at beginning of year...... 1,495,500 $11.13 645,000 $10.00
Granted............................... 693,500 24.91 856,500 11.97
Canceled.............................. (195,167) 11.09 (6,000) 9.38
Exercised............................. (96,531) 10.06 -- --
--------- ---------
Outstanding at end of year............ 1,897,302 $16.23 1,495,500 $11.13
Options exercisable at year-end....... 565,580 $11.01 261,667 $10.31
Options available for future grant.... 542 131,032
Weighted average fair value of options
granted during the year............. $ 11.48 $ 4.66
</TABLE>

F-18
<PAGE> 79

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The fair value of each option granted during the periods presented is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following assumptions: (i) dividend yield of 0%, (ii) expected volatility of
41.16% and 35.07% in the years 1996 and 1995, respectively, (iii) risk-free
interest rate of 6.21% and 5.58% in the years 1996 and 1995, respectively, and
(iv) expected life of 5 years.

<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------- -------------------------
NUMBER
RANGE OF NUMBER WGTD. AVG. WGTD. AVG. EXERCISABLE WGTD. AVG.
EXERCISE OUTSTANDING REMAINING EXERCISE AT EXERCISE
PRICES AT 12/31/96 CONTRACTUAL LIFE PRICE 12/31/96 PRICE
-------- ----------- ---------------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C>
$9 -- $19 .............. 1,214,802 8 11.26 565,580 11.01
$19 -- $29 .............. 389,500 10 19.40 -- --
$29 -- $39 .............. 293,000 10 32.59 -- --
--------- -- ----- ------- -----
$9 -- $39 .............. 1,897,302 9 16.23 565,580 11.01
========= == ===== ======= =====
</TABLE>

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 1996 and prior years. Sales to the following customers
exceeded 10% of revenues during the years indicated (expressed in thousands):

<TABLE>
<CAPTION>
1996 1995 1994
-------- ------- -------
<S> <C> <C> <C>
Enron Corp., its subsidiaries and affiliates......... $ 33,074 $17,431 $73,658
Shell Oil Company.................................... 110,131 79,927 --
Murphy Oil USA, Inc.................................. 23,338 24,193 --
</TABLE>

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
industry. 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, 1996, the total estimate
of these costs on the Company's oil and gas properties was approximately $84.0
million, estimated to be incurred through the year 2011. 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

F-19
<PAGE> 80

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 $2.0 million and a pledge
of certain rights to escrowed funds. The Company has posted with the MMS an area
wide bond of $3.0 million and supplemental bonds totaling $17.1 million.
Pursuant to a schedule previously imposed by the MMS, the Company will be
required to post additional supplemental bonds up to a 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. In addition, the Company is
currently working with the MMS to determine the level of supplemental bonding
(and the timing thereof) which will be required for some of the recently
acquired Central Gulf Properties. 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.

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. As amended by the Coast Guard Authorization Act of 1996, OPA requires
responsible parties for offshore facilities to provide financial assurance in
the amount of $35 million to cover potential OPA liabilities. This amount is
subject to upward regulatory adjustment up to $150 million.

In 1996, Statement of Position 96-1 ("SOP 96-1") -- Environmental
Remediation Liabilities was issued. The Company is required to adopt SOP 96-1 in
1997. The Company believes adoption of SOP 96-1 will not have a material effect
on its results of operations or financial position.

Total rental expenses under operating leases amounted to approximately
$690,000, $527,000 and $297,000 in 1996, 1995 and 1994, respectively.

In connection with the Initial Offerings, the Company entered into a
Registration Rights Agreement (the "Registration Agreement") entitling Enron 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. During 1996, the unregistered shares subject to the Registration Agreement
were transferred by Enron to Merrill Lynch Capital Markets, plc., together with
Enron's rights under the Registration Agreement.

F-20
<PAGE> 81

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. HEDGING ACTIVITIES

The Company hedges certain of its production through master swap agreements
("Swap Agreements"). The Swap Agreements provide for separate contracts tied to
the NYMEX light sweet crude oil and natural gas futures contracts. The Company
has contracts which contain specific contracted prices ("Swaps") that are
settled monthly based on the differences between the contract prices and the
average NYMEX prices for each month applied to the related contract volumes. To
the extent the average NYMEX price exceeds the contract price, the Company pays
the spread, and to the extent the contract price exceeds the average NYMEX price
the Company receives the spread. In addition, the Company has combined contracts
which have agreed upon price floors and ceilings ("Costless Collars"). To the
extent the average NYMEX price exceeds the contract ceiling, the Company pays
the spread between the ceiling and the average NYMEX price applied to the
related contract volumes. To the extent the contract floor exceeds the average
NYMEX price, the Company receives the spread between the contract floor and the
average NYMEX price applied to the related contract volumes. Under the terms of
the Swap Agreements, each counterparty has extended the Company a $5 million
line of credit for use in conjunction with its hedging activities. As of
February 24, 1997, the fair market value of all contracts covered by the Swap
Agreements was approximately $0.6 million.

As of December 31, 1996, after giving effect to three additional oil Swaps
that the Company entered into in February 1997, the Company's open forward
position on its outstanding crude oil Swaps was as follows:

<TABLE>
<CAPTION>
AVERAGE
MBBLS PRICE
----- -------
<S> <C> <C>
1997........................................................ 1,500 $19.73
1998........................................................ 300 18.55
1999........................................................ 300 18.55
2000........................................................ 300 18.55
----- ------
2,400 $19.29
===== ======
</TABLE>

The Company currently has no outstanding natural gas Swaps.

As of December 31, 1996, after giving effect to three additional Costless
Collars entered into through February 24, 1997, the Company's open forward
position on its outstanding Costless Collars was as follows:

<TABLE>
<CAPTION>
CONTRACTED CONTRACTED CONTRACTED
VOLUMES FLOOR CEILING
YEAR FROM THROUGH (MBBLS) PRICE PRICE
---- ---- ------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
1997........................ January March 600 $21.00 $24.45
1997........................ January June 1,200 $20.00 $24.25
1997........................ April June 375 $20.00 $25.14
1997........................ July September 900 $20.00 $24.40
</TABLE>

Revenue was increased (decreased) under the Swap Agreements by
approximately $(18.7) million, $(0.5) million and $1.7 million, respectively,
for the years ended December 31, 1996, 1995 and 1994.

F-21
<PAGE> 82

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair value as of December 31, 1996 and 1995, of financial
instruments other than current assets and liabilities is presented in the
following table:

<TABLE>
<CAPTION>
ESTIMATED FAIR ESTIMATED FAIR ESTIMATED FAIR ESTIMATED FAIR
VALUE VALUE VALUE VALUE
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Debt
Senior Notes............ $ 125,000,000) $ 149,375,000) $(125,000,000) $(141,875,000)
Senior Subordinated
Notes................ (159,141,999) (168,690,519) -- --
Shell Note.............. -- -- (15,183,735) (15,094,232)
Revolving Credit
Facility............. -- -- (32,200,000) (32,200,000)
------------- ------------- ------------- -------------
$(284,141,999) $(318,065,519) $(172,383,735) $(189,169,232)
============= ============= ============= =============
Hedges
Gas..................... $ -- $ -- $ -- $ (2,423,240)
Oil..................... -- (4,555,720) -- 950,750
------------- ------------- ------------- -------------
$ -- $ (4,555,720) $ -- $ (1,472,490)
============= ============= ============= =============
</TABLE>

15. OIL AND GAS RESERVE INFORMATION -- UNAUDITED

The Company's net proved oil and gas reserves at December 31, 1996, 1995
and 1994, have been determined by independent petroleum consultants in
accordance with guidelines established by the SEC and the Financial Accounting
Standards Board. 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 and the Company's policy regarding fuel gas.

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.

F-22
<PAGE> 83

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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(1)
(MBBL) (MMCF)
------ --------------
<S> <C> <C>
Proved reserves as of December 31, 1993..................... 21,093 52,724
Revisions of previous estimates........................... 1,979 7,294
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 (sold by the Company).......................... (2,771) (3,456)
Production (consumed by the Company)...................... -- (3,220)
------ -------
Proved reserves as of December 31, 1994..................... 33,044 83,348
Revisions of previous estimates........................... 4,857 9,093
Extensions, discoveries, and other additions.............. 1,640 10,647
Purchase of producing properties.......................... 345 85
Production (sold by the Company).......................... (6,057) (12,393)
Production (consumed by the Company)...................... -- (3,576)
------ -------
Proved reserves as of December 31, 1995..................... 33,829 87,204
Revisions of previous estimates........................... 2,546 23,935
Extensions, discoveries, and other additions.............. 9,766 31,060
Sale of production properties............................. (450) (9,929)
Purchase of producing properties.......................... 12,234 35,171
Production (sold by the Company).......................... (7,149) (18,720)
Production (consumed by the Company)...................... -- (3,363)
------ -------
Proved reserves as of December 31, 1996..................... 50,776 145,358
====== =======
Proved developed reserves:
As of December 31, 1994................................... 30,088 77,019
As of December 31, 1995................................... 31,702 84,258
As of December 31, 1996................................... 38,347 109,574
</TABLE>

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

(1) The Company includes as proven reserves, future gas production estimated by
Netherland, Sewell & Associates, Inc., to be used as fuel gas.

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 Financial Accounting Standards Board. The oil, condensate and gas
price structure utilized to project future net cash flows reflects current
prices at each year end and have been escalated only where known and
determinable price changes are provided by contracts and law. Crude prices have
declined significantly from December 31, 1996. Accordingly, the discounted
future net cash flows would be reduced if the standardized measure was
calculated at the latter date. Future production

F-23
<PAGE> 84

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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,
----------------------------------------
1996 1995 1994
------------ ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash flows................................. $1,789,544 $ 762,488 $ 645,091
Future production, development and abandonment
costs........................................... (907,770) (482,658) (433,193)
Income tax provision.............................. (204,733) (36,712) (11,530)
---------- --------- ---------
Future net cash flows............................. 677,041 243,118 200,368
10% annual discount............................... (144,549) (39,178) (35,390)
---------- --------- ---------
Standardized measure of discounted future net
cash flows...................................... $ 532,492 $ 203,940 $ 164,978
========== ========= =========
</TABLE>

<TABLE>
<CAPTION>
CHANGES IN STANDARDIZED MEASURE
PERIODS ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure at beginning of period......... $ 203,940 $164,978 $ 13,175
Sales and transfers of oil and gas produced, net of
production costs.................................. (159,361) (87,924) (21,214)
Changes in price, net of future production costs.... 242,943 61,865 34,412
Extensions and discoveries, net of future production
and development costs............................. 215,013 46,429 14,397
Repurchase of production payment.................... -- -- 106,572
Reserves transferred for resale..................... (10,009) -- --
Previously estimated development and abandonment
costs incurred during the period.................. 10,453 19,132 8,606
Revisions of quantity estimates..................... 88,994 46,761 8,184
Accretion of discount............................... 20,394 17,474 2,352
Net change in income taxes.......................... (130,226) (21,034) (9,762)
Purchase of reserves in place....................... 123,284 3,193 17,564
Changes in production rates (timing), estimated
development and abandonment costs, and other...... (72,933) (46,934) (9,308)
--------- -------- --------
Standardized measure at end of year................. $ 532,492 $203,940 $164,978
========= ======== ========
</TABLE>

16 QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized unaudited quarterly financial data for 1996 and 1995 are as
follows:

<TABLE>
<CAPTION>
QUARTER ENDED
---------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1996 1996 1996 1996
--------- -------- ------------- ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Net sales................................ 36,829 32,253 47,589 71,780
Gross profit............................. 11,147 6,918 16,487 32,148
Net income............................... 1,901 435 5,363 13,252
Earnings per common share:
Primary................................ $.12 $.02 $.26 $.63
Fully diluted.......................... $.12 $.02 $.26 $.63
</TABLE>

F-24
<PAGE> 85

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
QUARTER ENDED
---------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1995 1995 1995 1995
--------- -------- ------------- ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Net sales................................ 26,034 29,838 34,609 37,489
Gross profit............................. 6,354 7,381 8,089 12,016
Net income (loss)........................ (1,062) 811 1,052 9,101
Earnings per common share:
Primary................................ $(.07) $.05 $.07 $.60
Fully diluted.......................... $(.07) $.05 $.07 $.59
</TABLE>

17. EVENTS SUBSEQUENT TO DATE OF AUDITOR'S REPORT (UNAUDITED)

On March 7, 1997, the Company completed an acquisition of certain interests
in various state leases in the Main Pass 69 field, offshore Plaquemines Parish,
Louisiana, from Chevron U.S.A. Inc. for a gross purchase price of $55.7 million.
The acquisition includes interests in 27 producing wells located on 5,898 gross
acres. Post acquisition, the Company owns a 100% working interest in the 27
wells. Current estimated production from the newly acquired interest is
approximately 3,000 BOE per day net to the Company. The Company's ownership now
encompasses a total of approximately 22,000 gross acres in the Main Pass 69
field.

F-25
<PAGE> 86

OCEAN ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

<TABLE>
<CAPTION>
ASSETS
SEPTEMBER 30,
1997
-------------
<S> <C>
Current assets:
Cash and cash equivalents................................. $ 7,053,437
Joint interest receivables................................ 8,572,028
Oil and gas sales receivables............................. 35,966,008
Accounts receivable -- other.............................. 1,607,128
Assets held for resale.................................... --
Prepaid expenses.......................................... 846,613
Other current assets...................................... 4,486,343
-------------
Total current assets.............................. 58,531,557
Oil and gas properties -- full cost method:
Evaluated................................................. 735,314,377
Less accumulated depreciation, depletion, and
amortization........................................... (272,618,395)
-------------
462,695,982
Unevaluated properties excluded from amortization......... 149,825,472
Other assets:
Furniture and equipment, less accumulated depreciation of
$4,496,613 at September 30, 1997....................... 5,492,797
Restricted deposits....................................... 7,955,599
Deferred financing costs.................................. 10,474,003
-------------
Total assets...................................... $ 694,975,410
=============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities.................. $ 91,195,997
Oil and gas sales payable................................. 7,154,725
Accrued interest.......................................... 12,612,331
Current notes payable..................................... --
Deposit on assets held for resale......................... --
-------------
Total current liabilities......................... 110,963,053
Long-term debt.............................................. 464,121,495
Deferred hedge revenue...................................... 300,000
Deferred tax liability...................................... 7,547,042
Stockholders' equity:
Preferred stock, $.01 par value; authorized 10,000,000
shares, no shares issued or outstanding at September
30, 1997............................................... --
Common stock, $.01 par value; authorized 100,000,000
shares; issued and outstanding 19,702,010 shares at
September 30, 1997..................................... 197,020
Paid-in capital........................................... 93,258,324
Retained earnings......................................... 18,588,476
-------------
Total stockholders' equity........................ 112,043,820
-------------
Total liabilities and stockholders' equity........ $ 694,975,410
=============
</TABLE>

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

F-26
<PAGE> 87

OCEAN ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Oil and gas sales........................................... $204,396,286 $116,671,049
Operating expenses:
Lease operations.......................................... 40,477,049 24,930,765
Severance taxes........................................... 8,060,697 8,710,408
Depreciation, depletion and amortization.................. 83,926,173 48,477,198
------------ ------------
Total operating expenses.......................... 132,463,919 82,118,371
General and administrative expenses......................... 13,321,319 9,946,556
Interest expense............................................ 21,236,286 12,028,892
Other income................................................ (1,107,994) (173,027)
------------ ------------
Income before taxes and extraordinary item.................. 38,482,756 12,750,257
Income tax expense.......................................... 13,730,716 5,051,264
------------ ------------
Income before extraordinary item............................ 24,752,040 7,698,993
------------ ------------
Extraordinary loss on early extinguishment of debt, net of
taxes..................................................... 19,301,013 --
------------ ------------
Net income (loss)........................................... $ 5,451,027 $ 7,698,993
============ ============
Earnings (loss) per common share:
Primary
Before extraordinary item.............................. $ 1.18 $ 0.40
Extraordinary item..................................... (0.92) --
------------ ------------
Net income........................................... $ 0.26 $ 0.40
Fully diluted
Before extraordinary item.............................. $ 1.17 $ 0.40
Extraordinary item..................................... (0.91) --
------------ ------------
Net income........................................... $ 0.26 $ 0.40
Weighted average common and common equivalent shares
outstanding:
Primary................................................ 20,954,384 19,172,901
Fully diluted.......................................... 21,206,529 19,414,173
</TABLE>

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

F-27
<PAGE> 88

OCEAN ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Operating activities:
Net income (loss)......................................... $ 5,451,027 $ 7,698,993
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization:
Oil and gas properties............................... 83,926,173 48,477,198
Furniture and equipment.............................. 1,723,629 1,024,862
Deferred hedge revenue................................. (100,000) (352,750)
Deferred tax expense................................... 1,448,898 4,915,853
Changes in operating assets and liabilities:
Accrued interest....................................... 7,091,261 2,190,117
Receivables............................................ (8,873,515) (5,453,805)
Prepaid expenses....................................... 366,530 (419,185)
Other current assets................................... (2,071,539) (421,752)
Accounts payable and accrued liabilities............... 22,542,484 1,695,917
Oil and gas sales payable.............................. (675,690) (261,752)
------------ ------------
Net cash provided by operating activities................... 110,829,258 59,093,696
------------ ------------
Investing activities:
Additions to oil and gas properties and furniture and
equipment.............................................. (322,743,754) (209,829,151)
Increase in restricted deposits........................... (1,632,084) (1,551,499)
Proceeds from sale of oil and gas properties.............. 33,480,000 --
------------ ------------
Net cash used in investing activities....................... (290,895,838) (211,380,650)
------------ ------------
Financing activities:
Sale of stock............................................. 1,439,472 62,348,705
Borrowings on notes payable............................... 479,160,000 231,620,000
Payments of notes payable................................. (299,382,154) (117,747,726)
Deferred financing costs.................................. 143,719 (5,163,369)
------------ ------------
Net cash provided by financing activities................... 181,361,037 171,057,610
------------ ------------
Increase in cash and cash equivalents....................... 1,294,459 18,770,656
Cash and cash equivalents, beginning of the period.......... 5,758,978 212,238
------------ ------------
Cash and cash equivalents, end of the period................ $ 7,053,437 $ 18,982,894
============ ============
Interest paid during the period............................. $ 35,402,120 $ 12,056,670
============ ============
</TABLE>

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

F-28
<PAGE> 89
OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. GENERAL INFORMATION

The consolidated financial statements included herein have been prepared by
Ocean Energy, 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. Certain reclassifications have been
made to conform financial statement presentation between periods. 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 share applicable to common stock are based on the weighted
average number of shares of common stock outstanding for the periods, including
common equivalent shares which reflect the effect of stock options, to the
extent that they are dilutive, granted to certain employees and outside
directors on various dates through September 30, 1997. As of September 30, 1997
and 1996, the Company had 2,510,015 and 1,972,902 stock options outstanding,
respectively. The table below reflects the weighted average common, primary and
fully diluted shares outstanding for the 1997 and 1996 periods.

<TABLE>
<CAPTION>
NINE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
1997 1996 1997 1996
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Weighted average common shares
outstanding...................... 19,670,610 18,270,707 19,701,901 19,556,911
Primary common equivalent shares... 1,283,774 902,194 1,370,162 1,149,147
---------- ---------- ---------- ----------
Weighted average common and primary
common equivalent shares
outstanding...................... 20,954,384 19,172,901 21,072,063 20,706,058
Additional fully diluted shares.... 252,145 241,272 256,853 62,828
---------- ---------- ---------- ----------
Weighted average common and fully
diluted common equivalent shares
outstanding...................... 21,206,529 19,414,173 21,328,916 20,768,886
========== ========== ========== ==========
</TABLE>

In February, 1997, the Financial Accounting Standards Board ("FASB") issued
Statement No. 128 ("SFAS 128"), "Earnings Per Share", which simplifies the
computation of earnings per share ("EPS"). SFAS 128 is effective for financial
statements issued for periods ending after December 15, 1997, and requires
restatement for all prior period EPS data presented. Pro forma EPS and EPS
assuming dilution calculated in accordance with SFAS 128 after the extraordinary
charge was $(0.54) per share and $(0.51) per share, respectively, for the three
months ended September 30, 1997, and $0.27 per share and $0.26 per share,
respectively, for the three months ended September 30, 1996. Pro forma EPS and
EPS assuming dilution calculated in accordance with SFAS 128 after the
extraordinary charge was $0.28 per share and $0.26 per share, respectively, for
the nine months ended September 30, 1997, and $0.42 per share and $0.40 per
share, respectively, for the nine months ended September 30, 1996.

3. HEDGING ACTIVITIES

The Company engages in futures contracts with a portion of its production
through master swap agreements ("Swap Agreements"). The Company considers these
futures contracts to be hedging activities and, as such, monthly settlements on
these contracts are reflected in oil and gas sales. In order to consider these
futures contracts as hedges, (i) the Company must designate the futures contract
as a hedge of future production and (ii) the contract must reduce the Company's
exposure to the risk of changes in prices. Changes in the market value of
futures contracts treated as hedges are not recognized in income until the

F-29
<PAGE> 90
OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

hedged item is also recognized in income. If the above criteria are not met, the
Company will record the market value of the contract at the end of each month
and recognize a related gain or loss. Proceeds received or paid relating to
terminated contracts or contracts that have been sold are amortized over the
original contract period and reflected in oil and gas sales.

The Swap Agreements provide for separate contracts tied to the NYMEX light
sweet crude oil and natural gas futures contracts. The Company has contracts
which contain specific contracted prices ("Swaps") that are settled monthly
based on the differences between the contract prices and the average NYMEX
prices for each month applied to the related contract volumes. To the extent the
average NYMEX price exceeds the contract price, the Company pays the spread, and
to the extent the contract price exceeds the average NYMEX price the Company
receives the spread. Under the terms of the Swap Agreements, each counterparty
has extended the Company a $5 million line of credit in conjunction with it
hedging activities. As of November 3, 1997, the Company's exposure under all
contracts covered by the Swap Agreements was approximately $4.0 million.

As of September 30, 1997, the Company's open forward position on its
outstanding crude oil Swaps was as follows:

<TABLE>
<CAPTION>
AVERAGE
YEAR MBBLS PRICE
---- ----- -------
<S> <C> <C>
1997.......................................... 975 $19.93
1998.......................................... 4,800 $19.80
1999.......................................... 300 $18.55
2000.......................................... 300 $18.55
----- ------
Total......................................... 6,375 $19.70
===== ======
</TABLE>

The Company currently has no outstanding natural gas Swaps.

In addition, on April 7, 1997, the Company entered into a field diesel swap
for 150,000 gallons per month for the month of April 1997, and August 1997
through March 1998, relating to expected future diesel needs. This swap
obligates the Company to make or receive payments on the last day of each
respective calendar month based on the difference between $0.5425 per gallon and
the average of the daily settlement price per gallon for the respective calendar
month Platt's Gulf Coast Pipeline mean high sulfur 2 oil contract.

4. INVESTMENT IN OIL AND GAS PROPERTIES

On January 3, 1997, the Company completed the sale of its interest in the
South Marsh Island 269 field, located in federal waters offshore Louisiana. The
Company realized proceeds of $37.2 million from the sale. The Company owned a
non-operated working interest of approximately 20% in three blocks in the field.
No gain or loss was recognized on the sale.

On March 7, 1997, the Company completed an acquisition of certain interests
in various state leases in the Main Pass Block 69 field, offshore Plaquemines
Parish, Louisiana for a net purchase price of $55.9 million (the "Main Pass
Acquisition"). The acquisition included interests in 27 producing wells located
on 5,898 gross acres situated contiguous to the Company's pre-existing Main Pass
69 holdings. Following the acquisition, the Company owns a 100% working interest
in the 27 wells.

F-30
<PAGE> 91

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On October 15, 1997, the Company acquired certain oil and gas interests in
various federal leases in the South Pass 61 and 65 fields (the "South Pass
Properties") from Shell Offshore, Inc. ("SOI") and its affiliate for a gross
purchase price of $60.8 million. The Company has acquired a 50% working interest
in the fields and has become operator of the properties. The acquisition
includes interests in 95 producing wells located on approximately 26,250 gross
acres. Current estimated production from the newly acquired interests is
approximately 3,500 barrels of oil equivalent per day net to the Company.

On October 15, 1997, the Company also entered into an exploratory Joint
Venture Agreement with SOI which establishes an Area of Mutual Interest covering
approximately 240 square miles located in coastal and offshore areas of
Plaquemines Parish, Louisiana. Under the terms of the oil and gas exploration
agreement, the Company and SOI have agreed to contribute existing leasehold,
project inventory and proprietary 3-D seismic data within the AMI. The Company
expects the venture to spud the initial exploratory well in 1998.

5. RECENT OFFERINGS

On July 2, 1997, the Company completed an offering of $200 million of
8 7/8% Senior Subordinated Notes due 2007 (the "8 7/8% Notes") at a discount for
proceeds of approximately $199.7 million (before offering costs). Interest will
be payable semi-annually on January 15 and July 15 of each year commencing
January 15, 1998. Proceeds to the Company were approximately $195.2 million,
which were used primarily to finance the purchase of the 13 1/2% Notes (See Note
6) and to repay outstanding indebtedness under the Company's $250 million
amended and restated senior revolving bank credit facility dated October 15,
1997 (the "Revolving Credit Facility"). The remainder of the proceeds were used
for general corporate and working capital purposes. On August 1, 1997, the
Company filed a registration statement to register notes with the Securities and
Exchange Commission which were identical to the Notes issued on July 2, 1997, in
order to exchange these Notes for registered notes. Such exchange offer was
completed on October 2, 1997.

On October 16, 1997, the Company filed a Registration Statement on Form S-3
related to the underwritten public offering by the Company of 3,500,000 shares
of common stock. If the Company sells all of such shares, net proceeds to the
Company are estimated to be as much as approximately $215 million, a portion of
which will be used to repay outstanding indebtedness under its Revolving Credit
Facility. As of November 3, 1997, the outstanding balance on the Revolving
Credit Facility was $180.0 million. Of this amount, approximately $60.8 million
was incurred to finance the acquisition of the South Pass Properties, with the
remainder incurred during 1997 to date in connection with the Company's
exploration, development and production activities and for general corporate
purposes. The remaining net proceeds, if any, will be used for exploration and
exploitation drilling activities and for possible future acquisitions, as well
as for other general corporate purposes.

6. REPURCHASE OF 13 1/2% NOTES

On July 22, 1997, the Company amended the Indenture governing its 13 1/2%
Senior Notes due 2004 (the "13 1/2% Notes"), removing the principal restrictive
covenants and repurchased approximately $124.8 million of the $125 million in
original principal amount of the 13 1/2% Notes for approximately $151.5 million.
This purchase resulted in an extraordinary charge of $19.3 million, net of taxes
of $11.6 million. The extraordinary charge represented the difference between
the purchase price and related expenses and the net carrying value of the
13 1/2% Notes.

7. NEW ACCOUNTING STANDARDS

In June 1997, the FASB issued Statement No. 130 ("SFAS 130"), "Reporting
Comprehensive Income", and Statement No. 131 ("SFAS 131"), "Disclosures About
Segments of an Enterprise and Related Information". SFAS 130 establishes
standards for reporting and display of comprehensive income in the financial
statements. Comprehensive income is the total of net income and all other
non-owner changes in

F-31
<PAGE> 92

OCEAN ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

equity. SFAS 131 requires that companies disclose segment data based on how
management makes decisions about allocating resources to segments and measuring
their performance. SFAS 130 and 131 are effective for 1998. Adoption of these
standards is not expected to have an effect on the Company's financial
statements, financial position or results of operations.

F-32
<PAGE> 93

======================================================

NO DEALER, SALESPERSON OR OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS IN CONNECTION WITH THE OFFERING
HEREIN, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE
RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR THE UNDERWRITERS. 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
Disclosure Regarding Forward-Looking
Statements......................... 11
Risk Factors......................... 11
Use of Proceeds...................... 16
Capitalization....................... 17
Price Range of Common Stock and
Dividend Policy.................... 18
Selected Historical Financial and
Operating Data..................... 19
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 21
Business............................. 34
Management........................... 50
Selling Stockholders................. 52
Certain United States Federal Tax
Consequences to Non-U.S. Holders... 52
Underwriting......................... 54
Legal Matters........................ 56
Experts.............................. 56
Available Information................ 56
Incorporation of Certain Documents by
Reference.......................... 56
Glossary of Certain Oil and Gas
Terms.............................. 58
Index to Financial Statements........ F-1
</TABLE>

======================================================

3,600,000 SHARES

[OCEAN ENERGY LOGO]

COMMON STOCK

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

PROSPECTUS
---------------------------

MERRILL LYNCH & CO.

LEHMAN BROTHERS

HOWARD, WEIL,
LABOUISSE, FRIEDRICHS
INCORPORATED

MORGAN STANLEY DEAN WITTER

PETRIE PARKMAN & CO.

SMITH BARNEY INC.

NOVEMBER 12, 1997

======================================================
<PAGE> 94

[ALTERNATE PAGE FOR INTERNATIONAL PROSPECTUS]

FILED PURSUANT TO RULE 424(B)(4)

REGISTRATION NO. #333-37985

PROSPECTUS

3,600,000 SHARES

[OCEAN ENERGY LOGO]

COMMON STOCK
---------------------

Of the shares of Common Stock being offered hereby, 720,000 shares (the
"International Shares") are being offered outside the United States and Canada
(the "International Offering") by the International Managers and 2,880,000
shares (the "U.S. Shares") are being offered in the United States and Canada
(the "U.S. Offering" and, together with the International Offering, the
"Offerings") by the U.S. Underwriters. The price to public and underwriting
discount per share are identical for both Offerings and the closings for both
Offerings are conditioned upon each other. See "Underwriting."

SEE "RISK FACTORS" BEGINNING ON PAGE 11 FOR CERTAIN CONSIDERATIONS RELEVANT
TO AN INVESTMENT IN THE COMMON STOCK OFFERED HEREBY.
---------------------
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.

(1) The Company and the Selling Stockholders have agreed to indemnify the
several Underwriters against certain liabilities under the Securities Act of
1933, as amended. See "Underwriting."

(2) Before deducting expenses payable by the Company estimated at $550,000.

(3) One of the Selling Stockholders has granted to the International Managers
and U.S. Underwriters options for 30 days to purchase up to 108,000 and
432,000 additional shares of Common Stock, respectively, at the Price to
Public, less Underwriting Discount, solely to cover over-allotments, if any.
If such option is exercised in full, the Price to Public, Underwriting
Discount and Proceeds to Selling Stockholders will be $247,882,500,
$9,894,600 and $59,784,400, respectively. See "Underwriting."

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

---------------------
MERRILL LYNCH INTERNATIONAL LEHMAN BROTHERS

HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
MORGAN STANLEY DEAN WITTER
PETRIE PARKMAN & CO.
SMITH BARNEY INC.
---------------------

THE DATE OF THIS PROSPECTUS IS NOVEMBER 12, 1997.

<PAGE> 95

[ALTERNATE PAGE FOR INTERNATIONAL PROSPECTUS]

UNDERWRITING

Subject to the terms and conditions set forth in the international purchase
agreement (the "International Purchase Agreement") among the Company, the
Selling Stockholders and each of the underwriters named below (the
"International Managers"), the Company and the Selling Stockholders have agreed
to sell to each of the International Managers, and each of the International
Managers has severally agreed to purchase, the number of shares of Common Stock
set forth below opposite their respective names.

<TABLE>
<CAPTION>
NUMBER
INTERNATIONAL MANAGERS OF SHARES
---------------------- ---------
<S> <C>
Merrill Lynch International................................. 120,000
Lehman Brothers International (Europe)...................... 120,000
Howard, Weil, Labouisse, Friedrichs Incorporated............ 120,000
Morgan Stanley & Co. International Limited.................. 120,000
Petrie Parkman & Co., Inc................................... 120,000
Smith Barney Inc............................................ 120,000
-------
Total.......................................... 720,000
=======
</TABLE>

The Company and the Selling Stockholders have also entered into a U.S.
purchase agreement (the "U.S. Purchase Agreement") with certain other
underwriters in the United States and Canada (the "U.S. Underwriters" and,
together with the International Managers, the "Underwriters"), for whom Merrill
Lynch, Pierce, Fenner & Smith Incorporated ("Merrill Lynch"), Lehman Brothers
Inc. (collectively, the co-lead managers), Howard, Weil, Labouisse, Friedrichs
Incorporated, Morgan Stanley & Co. Incorporated, Petrie Parkman & Co., Inc. and
Smith Barney Inc. are acting as representatives (the "U.S. Representatives").
Subject to the terms and conditions set forth in the U.S. Purchase Agreement,
and concurrently with the sale of 720,000 shares of Common Stock to the
International Managers pursuant to the International Purchase Agreement, the
Company and the Selling Stockholders have agreed to sell to the U.S.
Underwriters, and the U.S. Underwriters severally have agreed to purchase from
the Company and the Selling Stockholders, an aggregate of 2,880,000 shares of
Common Stock. The public offering price per share of Common Stock and the total
underwriting discount per share are identical under the International Purchase
Agreement and the U.S. Purchase Agreement.

In the International Purchase Agreement and the U.S. Purchase Agreement,
the several International Managers and the several U.S. Underwriters,
respectively, have agreed, subject to the terms and conditions set forth
therein, to purchase all of the shares of Common Stock being sold pursuant to
each such Purchase Agreement if any of such shares are purchased. Under certain
circumstances, the commitments of non-defaulting International Managers or U.S.
Underwriters (as the case may be) may be increased as set forth in the
International Purchase Agreement and the U.S. Purchase Agreement, respectively.
The closing with respect to the sale of shares of Common Stock to be purchased
by the International Managers and the U.S. Underwriters are conditioned upon one
another.

The International Managers and the U.S. Underwriters have entered into an
intersyndicate agreement (the "Intersyndicate Agreement") that provides for the
coordination of their activities. Under the terms of the Intersyndicate
Agreement, the Underwriters are permitted to sell shares of Common Stock to each
other for the purposes of resale at the public offering price, less an amount
not greater than the selling concession. Under the terms of the Intersyndicate
Agreement, the International Managers and any dealer to whom they sell shares of
Common Stock will not offer to sell or sell shares of Common Stock to persons
who are United States or Canadian persons or to persons they believe intend to
resell to persons who are United States or Canadian persons, and the U.S.
Underwriters and any dealer to whom they sell shares of Common Stock will not
offer to sell or sell shares of Common Stock to persons who are non-United
States and non-Canadian persons or to persons they believe intend to resell to
persons who are non-United States persons or non-Canadian persons, except, in
each case, for transactions pursuant to the Intersyndicate Agreement.

The International Managers have advised the Company that they propose to
offer the shares of Common Stock offered hereby to the public at the public
offering price set forth on the cover page of this Prospectus,

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and to certain dealers at such price less a concession not in excess of $1.41
per share. The International Managers may allow, and such dealers may reallow, a
discount not in excess of $.10 per share on sales to certain other dealers.
After the International Offering, the public offering price, concession and
discount may be changed.

One of the Selling Stockholders has granted the International Managers an
option to purchase up to 108,000 additional shares of Common Stock at the public
offering price set forth on the cover page of this Prospectus, less the
underwriting discount. Such option, which expires 30 days after the date of this
Prospectus, may be exercised solely to cover over-allotments. To the extent that
the International Managers exercise such option, each of the International
Managers will be obligated, subject to certain conditions, to purchase
approximately the same percentage of the option shares that the number of shares
to be purchased initially by that International Manager bears to the total
number of shares to be purchased initially by the International Managers. The
same Selling Stockholder has also granted an option to the U.S. Underwriters,
which expires 30 days after the date of this Prospectus, to purchase up to
432,000 additional shares of Common Stock to cover over-allotments, if any, on
terms similar to those granted to the International Managers.

Each International Manager represents and agrees that (a) it has not
offered or sold and prior to the expiration of six months from the closing date
of the Offerings, will not offer or sell any shares of Common Stock to persons
in the United Kingdom, except to persons whose ordinary activities involve them
in acquiring, holding, managing or disposing of investments (as principal or
agent) for the purposes of their businesses or otherwise in circumstances which
have not resulted and will not result in an offer to the public in the United
Kingdom within the meaning of the Public Offers of Securities Regulations 1995,
(b) it has complied and will comply with all applicable provisions of the
Financial Services Act 1986 with respect to anything done by it in relation to
the Common Stock in, from or otherwise involving the United Kingdom, and (c) it
has only issued or passed on and will only issue or pass on to any person in the
United Kingdom any document received by it in connection with the issue or sale
of the Common Stock if that person is of a kind described in Article 11(3) of
the Financial Services Act 1986 (Investment Advertisements) (Exemptions) Order
1996 or is a person to whom such document may otherwise lawfully be issued or
passed on.

No action has been or will be taken in any jurisdiction (except in the
United States) that would permit a public offering of the shares of Common Stock
or the possession, circulation or distribution of this Prospectus or any other
material relating to the Company or the shares of Common Stock in any
jurisdiction where action for that purpose is required. Accordingly, the shares
of Common Stock may not be offered or sold, directly or indirectly, and neither
this Prospectus nor any other offering material or advertisements in connection
with the shares of Common Stock may be distributed or published, in or from any
country or jurisdiction except in compliance with any applicable rules and
regulations of such country or jurisdiction.

Purchasers of the shares of Common Stock offered hereby may be required to
pay stamp taxes and other charges in accordance with the laws and practices of
the country of purchase, in addition to the offering price set forth on the
cover page of this Prospectus.

The Company and its directors, including the Selling Stockholders, have
agreed that they will not, without the prior written consent of Merrill Lynch,
offer, sell or otherwise dispose of, any shares of Common Stock or any
securities convertible into shares of Common Stock, except for or upon the
exercise of currently outstanding options (except for the Offerings and the
over-allotment option granted to the Underwriters in the Offerings), for a
period of 90 days from the date of this Prospectus.

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the price of the Common Stock. Such transactions consist of bids or purchases
for the purposes of pegging, fixing or maintaining the price of the Common
Stock.

Neither the Company nor any of the Underwriters makes any representation or
prediction as to the direction or magnitude of any effect that the transactions
described above may have on the price of the Common Stock. In addition, neither
the Company nor any of the Underwriters makes any representation that the U.S.
Representatives will engage in such transactions or that such transactions, once
commenced, will not be discontinued without notice.

LEGAL MATTERS

EXPERTS

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[ALTERNATE PAGE FOR INTERNATIONAL PROSPECTUS]

AVAILABLE INFORMATION

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/A for the year ended
December 31, 1996;

b. The Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1997;

c. The Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1997;

d. The Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1997; and

e. The description of the Company's Common Stock contained in the
Company's Registration Statement on Form 8-A filed March 8, 1996.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary................... 3
Disclosure Regarding Forward-Looking
Statements......................... 11
Risk Factors......................... 11
Use of Proceeds...................... 16
Capitalization....................... 17
Price Range of Common Stock and
Dividend Policy.................... 18
Selected Historical Financial and
Operating Data..................... 19
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 21
Business............................. 34
Management........................... 50
Selling Stockholders................. 52
Certain United States Federal Tax
Consequences to Non-U.S. Holders... 52
Underwriting......................... 54
Legal Matters........................ 56
Experts.............................. 56
Available Information................ 57
Incorporation of Certain Documents by
Reference.......................... 57
Glossary of Certain Oil and Gas
Terms.............................. 58
Index to Financial Statements........ F-1
</TABLE>

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3,600,000 SHARES

[OCEAN ENERGY LOGO]

COMMON STOCK

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

PROSPECTUS
---------------------------

MERRILL LYNCH INTERNATIONAL

LEHMAN BROTHERS

HOWARD, WEIL,
LABOUISSE, FRIEDRICHS
INCORPORATED

MORGAN STANLEY DEAN WITTER

PETRIE PARKMAN & CO.

SMITH BARNEY INC.

NOVEMBER 12, 1997

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