ENERGY PARTNERS LTD, S-1/A, 2000-09-21

ENERGY PARTNERS LTD
S-1/A, 2000-09-21
BUSINESS SERVICES, NEC

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<PAGE> 1

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 21, 2000

REGISTRATION NO. 333-42876
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------

AMENDMENT NO. 1
TO
FORM S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
---------------------

ENERGY PARTNERS, LTD.
(Exact name of registrant as specified in its charter)

<TABLE>
<S> <C> <C>
DELAWARE 1311 72-1409562
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification Number)
</TABLE>

201 ST. CHARLES AVENUE, SUITE 3400
NEW ORLEANS, LA 70170
(504) 569-1875
(Address, including zip code, and telephone number, including
area code, of registrant's principal executive offices)
---------------------

RICHARD A. BACHMANN
CHAIRMAN, PRESIDENT AND
CHIEF EXECUTIVE OFFICER
ENERGY PARTNERS, LTD.
201 ST. CHARLES AVENUE, SUITE 3400
NEW ORLEANS, LA 70170
(504) 569-1875
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
---------------------

Copies To:

<TABLE>
<S> <C> <C>
JEAN M. STALLARD, ESQ. JOHN SCHUSTER, ESQ. DARRELL W. TAYLOR, ESQ.
VICE PRESIDENT-GENERAL COUNSEL CAHILL GORDON & REINDEL BAKER BOTTS L.L.P.
ENERGY PARTNERS, LTD. 80 PINE STREET ONE SHELL PLAZA
201 ST. CHARLES AVENUE, SUITE 3400 NEW YORK, NY 10005-1702 910 LOUISIANA STREET
NEW ORLEANS, LA 70170 (212) 701-3000 HOUSTON, TX 77002-4995
(504) 569-1875 (713) 229-1234
</TABLE>

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

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [ ]

If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
---------------------

CALCULATION OF REGISTRATION FEE

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------
TITLE OF EACH CLASS OF SECURITIES PROPOSED MAXIMUM AMOUNT OF
TO BE REGISTERED AGGREGATE OFFERING PRICE(1) REGISTRATION FEE(2)
-------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock, no par value................................ $125,637,500 $33,168
-------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Estimated solely for the purpose of calculating the amount of the
registration fee pursuant to Rule 457(o) under the Securities Act.

(2) The registrant paid $33,000 of the registration fee with its filing on
August 2, 2000.

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

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE> 2

EXPLANATORY NOTE

This registration statement contains two forms of prospectus: one to be
used in connection with an underwritten offering of our common stock in the
United States and Canada, and one to be used in a concurrent international
offering of our common stock. The U.S. prospectus for the offering in the United
States and Canada follows immediately after this explanatory note. After the
U.S. prospectus are the alternate pages for the international prospectus. Copies
of the complete U.S. prospectus and international prospectus in the exact forms
in which they are to be used after effectiveness will be filed with the
Securities and Exchange Commission pursuant to Rule 424(b) under the Securities
Act.
<PAGE> 3

The information in this prospectus is not complete and may be changed. We
may not sell these securities until the registration statement filed with
the Securities and Exchange Commission is effective. This prospectus is
not an offer to sell these securities and it is not soliciting an offer
to buy these securities in any state where the offer or sale is not
permitted.

SUBJECT TO COMPLETION

PRELIMINARY PROSPECTUS DATED SEPTEMBER 21, 2000

P R O S P E C T U S

5,750,000 SHARES

[LOGO]
ENERGY PARTNERS, LTD.
COMMON STOCK
----------------------

This is our initial public offering. We are selling all of the shares. The
U.S. underwriters are offering 4,600,000 shares in the U.S. and Canada and the
international managers are offering 1,150,000 shares outside the U.S. and
Canada.

We expect the public offering price to be between $17 and $19 per share.
Currently, no public market exists for the shares. After pricing of the
offering, we expect that the shares will trade on the New York Stock Exchange
under the symbol "EPL."

INVESTING IN OUR COMMON STOCK INVOLVES RISKS THAT ARE DESCRIBED IN THE
"RISK FACTORS" SECTION BEGINNING ON PAGE 10 OF THIS PROSPECTUS.

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

<TABLE>
<CAPTION>
PER SHARE TOTAL
--------- -----
<S> <C> <C>
Public offering price...................................... $ $
Underwriting discount...................................... $ $
Proceeds, before expenses, to Energy Partners, Ltd......... $ $
</TABLE>

The U.S. underwriters may also purchase up to an additional 690,000 shares
at the public offering price, less the underwriting discount, within 30 days
from the date of this prospectus to cover over-allotments. The international
managers may similarly purchase up to an additional 172,500 shares from us.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.

The shares will be ready for delivery on or about , 2000.

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

MERRILL LYNCH & CO. UBS WARBURG LLC

DONALDSON, LUFKIN & JENRETTE HOWARD WEIL
A DIVISION OF LEGG MASON WOOD WALKER, INC.

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

The date of this prospectus is , 2000.
<PAGE> 4

[MAP OF U.S. GULF OF MEXICO AND OUR LEASEHOLD INTERESTS.]

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.......................................... 1
Risk Factors................................................ 10
Special Note Regarding Forward-Looking Statements........... 17
Use of Proceeds............................................. 18
Dividend Policy............................................. 18
Capitalization.............................................. 19
Dilution.................................................... 20
Selected Historical Financial Data.......................... 21
Unaudited Pro Forma Financial Information................... 23
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 27
Business and Properties..................................... 33
Management.................................................. 49
Principal Stockholders...................................... 55
Certain Transactions........................................ 57
Description of Capital Stock................................ 60
Shares Eligible for Future Sale............................. 65
Material U.S. Federal Income Tax Considerations for Non-U.S.
Holders of Our Common Stock............................... 67
Underwriting................................................ 70
Legal Matters............................................... 74
Experts..................................................... 74
Where You Can Find More Information......................... 74
Glossary of Oil and Natural Gas Terms....................... 75

Index to Financial Statements............................... F-1
Report of Independent Petroleum Engineers................... A-1
</TABLE>

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

You should rely only on the information contained in this prospectus. We
have not, and the underwriters have not, authorized any other person to provide
you with different information. If anyone provides you with different or
inconsistent information, you should not rely on it. We are not, and the
underwriters are not, making an offer to sell these securities in any
jurisdiction where the offer or sale is not permitted.
i
<PAGE> 5

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus.
You should read this entire prospectus carefully, including "Risk Factors" and
our financial statements and the notes to those financial statements included
elsewhere in this prospectus. We have provided definitions for some of the oil
and natural gas terms used in this prospectus in the "Glossary of Oil and
Natural Gas Terms" on page 75 of this prospectus. Unless otherwise indicated,
the information contained in this prospectus assumes that the underwriters do
not exercise their over-allotment options.

ABOUT ENERGY PARTNERS, LTD.

We are an independent oil and natural gas exploration and production
company concentrated in the shallow to moderate depth waters of the central
region of the Gulf of Mexico Shelf. This region contains over 500 oil and
natural gas fields, 25 of which have individually produced over 250 million
barrels of oil equivalent. Most of our properties are located in the Terrebonne
Trough area of this region. We have focused on this area because it provides us
with favorable economic and geologic conditions, including multiple reservoir
formations, regional economies of scale, extensive infrastructure and
comprehensive geologic databases. We believe that the large, established fields
in this region offer a balanced and ample inventory of existing and prospective
exploitation and development opportunities, as well as the long-term potential
for reserve additions and production increases from deeper geologic formations.

We were incorporated in January 1998 by Richard A. Bachmann, our chairman,
president and chief executive officer. Mr. Bachmann, the former president and
chief operating officer of The Louisiana Land and Exploration Company, assembled
a team of geoscientists and management professionals with considerable
region-specific geological, geophysical, technical and operational experience to
form the foundation of our company. The industry relationships of Mr. Bachmann
and the rest of our team provide us with access to the operators of the Gulf of
Mexico Shelf fields that we target for redevelopment. Our 11-member management
team has an average of 26 years of energy industry experience, many with large
energy companies. Our management and employees collectively will own or have
rights to acquire approximately 24.0% of our common stock after this offering.
In November 1999, Evercore Capital Partners L.P., a New York-based private
investment firm, invested $60.0 million in our company and will own
approximately 34.8% of our outstanding shares of common stock after this
offering.

We have grown our company through a combination of multi-year, multi-well
drill-to-earn programs and strategic acquisitions. Under our drill-to-earn
programs, we use our personnel and capital to identify and pursue additional
drilling opportunities on properties previously developed by our drill-to-earn
partners and recover our investment through sharing revenue from the new
production we establish. After successful drilling of wells, we earn an interest
in the reserves we find and develop. We generally operate the properties during
the drilling phase of these programs and seek to reduce costs and improve
reservoir recovery efficiencies through our geophysical, technical and
operational expertise. Early this year, we acquired Ocean Energy, Inc.'s
interest in the East Bay field and, in a series of transactions, increased our
interest in the South Timbalier 26 field.

Our proved reserves at January 1, 2000, including our acquisition of the
East Bay field and our increased interest in the South Timbalier 26 field, were
35.5 Mmboe (28.0 Mmbls of oil and 44.6 Bcf of natural gas, or 79% oil) and our
pre-tax SEC PV-10 (present value of future cash flows, assuming a discount rate
of 10% per annum) was $258.5 million, based on a reserve report prepared by
Netherland, Sewell & Associates, Inc. For the month ended June 30, 2000, our
daily oil production averaged approximately 9,200 Bbls and our daily natural gas
production averaged approximately 11,850 Mcf, or a total of 11,200 Boe per day.
Our pro forma EBITDAX (earnings before interest, taxes, depreciation, depletion
and amortization and exploration expenditures) was $47.4 million for the year
ended December 31, 1999 and $35.0 million for the six months ended June 30,
2000. Our pro forma net income was $8.2 million for the year ended December 31,
1999 and $16.1 million for the six months ended June 30, 2000.

1
<PAGE> 6

OUR STRATEGY

Our goal is to generate an attractive return on capital employed by
opportunistically entering into drill-to-earn programs or complementary
acquisitions in our core operating areas. We plan to achieve this goal by:

- Maintaining our Gulf of Mexico focus. We focus on the large, established
fields in the central Gulf of Mexico Shelf area because we believe that
this region's extensive infrastructure and favorable geologic conditions
will allow us to achieve attractive returns on our investments.

- Capitalizing on our geoscience expertise. Our geologists and
geophysicists internally generate and evaluate prospects in their current
area of focus and in connection with our new business initiatives. Our
drill-to-earn programs give our technical teams access to our partners'
technical databases to identify and implement successful and profitable
development, exploitation and exploration activities.

- Continuing to operate our properties. We seek to retain operatorship
following an acquisition or in connection with drill-to-earn programs. As
of June 30, 2000, we operated properties which comprised approximately
88% of our production.

- Expanding our asset base through additional drill-to-earn programs and
strategic acquisitions. We plan to identify new drill-to-earn and
acquisition opportunities by targeting both oil and natural gas
properties that have high cumulative production with low levels of
current production, significant identified proven reserves with potential
for large reserve additions, existing infrastructure and multiple
productive reservoir targets.

Risks related to our strategy. Prospective investors should carefully
consider the matters set forth under the caption "Risk Factors," as well as the
other information set forth in this prospectus, including that our future
operating results are difficult to forecast because we have a limited operating
history, the 3-D seismic data and other technologies we use cannot eliminate
exploration risk, our relatively small number of properties increases our
exposure to production problems, reserve estimate inaccuracies materially affect
the quantities and net present value of our reserves, our Gulf of Mexico focus
subjects us to higher reserve replacement needs, and the oil and natural gas
business involves many operating and financial risks. One or more of these
matters could negatively impact our ability to implement successfully our
business strategy.

2
<PAGE> 7

OUR PRINCIPAL OIL AND NATURAL GAS PROPERTIES

Currently, we have three specific project areas: East Bay; Greater Bay
Marchand; and Main Pass 122/133. South Timbalier 26, Bay Marchand and South
Timbalier 22, 23 and 27 collectively comprise what is known as the Greater Bay
Marchand area. The blocks are contiguous and together cover most of the large
Bay Marchand area located in state and federal waters offshore Louisiana. East
Bay has produced over 880 Mmboe and the Greater Bay Marchand area has produced
over 1,069 Mmboe. East Bay and the Greater Bay Marchand area are two of the ten
largest fields in the Gulf of Mexico, based on cumulative production.

The following table and accompanying narrative summarize our interests in
these properties, our significant transactions since our inception and our
rationale for each transaction. We discuss each property in more detail under
"Business and Properties -- Our Principal Oil and Natural Gas Properties."

<TABLE>
<CAPTION>
AS OF JANUARY 1, 2000 JUNE 2000
-------------------------------- AVERAGE DAILY
PROVED RESERVES PRE-TAX PRODUCTION
WORKING ---------------- SEC PV-10 --------------
PROJECT AREA INTEREST MBOE % OIL (IN MILLIONS) BOE % OIL
------------ --------- ------- ------ ------------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
East Bay................................... 98.5% 27,405 83% $183.5 8,150 85%
Greater Bay Marchand Area:
South Timbalier 26....................... 50.0 5,483 67 54.2 1,670 81
Bay Marchand............................. 12.5-45.0 1,411 83 11.0 785 80
South Timbalier 22, 23 and 27............ 12.5 383 67 1.8 115 72
------ ------ ------
Total Greater Bay Marchand Area........ 7,277 70 67.0 2,570 80
Main Pass 122/133.......................... 52.0-75.0 792 27 8.0 480 58
------ ------ ------
Total............................. 35,474 79 $258.5 11,200 82
====== ====== ======
</TABLE>

We acquired the East Bay field from Ocean Energy, Inc. effective January 1,
2000. Three oil and natural gas fields, South Pass 24, 27 and 39, comprise the
East Bay field. This property met all of our investment criteria and also
provided us with a significant source of stable production from a large number
of wells.

During the first half of 1998, we negotiated the purchase of a 100% working
interest in the South Timbalier 26 field from Shell Offshore, Inc. We brought in
Unocal Corporation as our partner in the transaction and, in June 1998, we
completed the purchase. We acquired a 20% working interest in and operatorship
of the field and Unocal acquired the remaining 80% working interest. Unocal
subsequently elected to dispose of its interest in the field, and effective
January 1, 2000, we acquired Unocal's 80% interest in the field. We subsequently
sold 50% of our working interest in the field to Vastar Resources, Inc. We
retained operatorship of the field.

Our interests in the Bay Marchand field originated from two drill-to-earn
programs with Chevron USA Inc. The first program covered the federal outer
continental shelf portion of the field and commenced in August 1998. In May
2000, we entered into the second drill-to-earn program, covering the portion of
the field located in Louisiana state waters.

We purchased our initial interest in South Timbalier 22, 23 and 27 in
October 1999. In September 2000, we acquired an additional 14.5% working
interest from Texaco Exploration and Production Inc. effective January 1, 2000.
Our reserves and production associated with this interest are not included in
the table above or other reserve and production information in this prospectus.

Our drill-to-earn program with Chevron covering Main Pass 122/133 generated
our first set of drilling opportunities. Our success with these wells provided
us with the operating history and track record to negotiate additional
drill-to-earn programs and acquisitions. We have completed this drill-to-earn
program and do not plan any additional capital investments for Main Pass
122/133.

3
<PAGE> 8

We have identified a substantial inventory of development, exploitation and
exploration projects which we are pursuing in East Bay and the Greater Bay
Marchand area. We believe this inventory provides us with significant
opportunities to increase our reserves and production. The following table
summarizes well projects and the estimated capital expenditures we currently
plan to undertake through December 31, 2002.

<TABLE>
<CAPTION>
ESTIMATED
CAPITAL
IDENTIFIED EXPENDITURES
PROJECT AREA PROJECTS (IN MILLIONS)
------------ ---------- -------------
<S> <C> <C>
East Bay.................................................... 172 $102.0
Greater Bay Marchand Area................................... 81 73.5
--- ------
Total............................................. 253 $175.5
=== ======
</TABLE>

OUR EXECUTIVE OFFICES

Our principal executive offices are located at 201 St. Charles Avenue,
Suite 3400, New Orleans, Louisiana 70170. Our telephone number is (504)
569-1875. Our Internet address on the World Wide Web is www.eplweb.com.
Information on our web site does not constitute part of this prospectus.

4
<PAGE> 9

THE OFFERING

Common stock offered by Energy
Partners:

U.S. offering.................. 4,600,000 shares

International offering......... 1,150,000 shares

Total.................. 5,750,000 shares

Shares outstanding after the
offering......................... 27,057,489 shares

Use of proceeds.................. We estimate that our net proceeds from this
offering without exercise of the
over-allotment options will be
approximately $95.1 million. We intend to
use these net proceeds:

- to repay indebtedness;

- to redeem preferred stock; and

- for general corporate purposes.

Please read "Use of Proceeds" for more
details regarding the allocation among the
listed uses.

Risk factors..................... Please read "Risk Factors" and other
information included in this prospectus for
a discussion of factors you should consider
carefully before deciding to invest in
shares of our common stock.

Proposed New York Stock Exchange
symbol........................... "EPL"

The number of shares outstanding after the offering excludes 413,000 shares
issuable on exercise of outstanding stock options at a weighted average exercise
price of $9.48 and 188,850 shares which are issuable under our benefit plans and
other rights to acquire shares. Please read "Capitalization" for more
information regarding our capitalization immediately following this offering.

5
<PAGE> 10

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

The summary historical financial data set forth below should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and with our financial statements and the notes to
those financial statements included elsewhere in this prospectus. The statement
of operations data for the period January 29, 1998 (inception) to December 31,
1998 and for the year ended December 31, 1999 and the balance sheet data as of
December 31, 1998 and 1999 were derived from our audited financial statements
included in this prospectus. The summary pro forma and historical financial data
as of June 30, 2000 and for the six-month periods ended June 30, 1999 and 2000
were derived from our unaudited consolidated financial statements, which in our
opinion include all adjustments (which consist only of normal recurring
adjustments) necessary for a fair presentation of our financial condition and
results of operations for such interim periods. The pro forma financial data set
forth below does not purport to represent what our financial condition or
results of operations actually would have been if the acquisitions that are
given pro forma effect in fact occurred on the assumed dates or to project our
financial condition or results of operations for any future period or date.

<TABLE>
<CAPTION>
JANUARY 29,
1998 PRO FORMA SIX MONTHS ENDED JUNE 30,
(INCEPTION) TO YEAR ENDED YEAR ENDED ----------------------------------
DECEMBER 31, DECEMBER 31, DECEMBER 31, PRO FORMA
1998 1999 1999(1) 1999 2000 2000(1)
-------------- ------------ ------------ -------- ----------- ---------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Statement of Operations Data:
Revenue..................................... $ 1,966 $ 9,509 $78,719 $ 3,780 $ 30,356 $56,401
-------- -------- ------- -------- -------- -------
Costs and Expenses:
Lease operating........................... 359 1,640 27,283 623 7,992 15,869
Exploration expenditures and dry hole
costs................................... -- 1,570 1,570 -- 824 824
Depreciation, depletion and
amortization............................ 1,303 4,525 23,300 1,936 8,2876 12,531
General and administrative................ 615 2,609 4,077 1,098 5,162 5,529
-------- -------- ------- -------- -------- -------
Total costs and expenses.............. 2,277 10,344 56,230 3,657 22,264 34,753
-------- -------- ------- -------- -------- -------
Income (loss) from operations............... (311) (835) 22,489 123 8,092 21,648
-------- -------- ------- -------- -------- -------
Interest income............................. 49 312 312 85 328 328
Interest expense............................ (802) (2,947) (9,877) (1,301) (3,057) (4,790)
Gain on sale of oil and gas assets.......... -- -- -- -- 7,781 7,781
-------- -------- ------- -------- -------- -------
Income (loss) before income taxes........... (1,064) (3,470) 12,924 (1,093) 13,144 24,967
Income taxes................................ 359 1,185 (4,716) 374 (4,623) (8,879)
-------- -------- ------- -------- -------- -------
Net income (loss)........................... $ (705) $ (2,285) $ 8,208 $ (719) $ 8,521 $16,088
======== ======== ======= ======== ======== =======
Net income (loss) available to common
stockholders(2)........................... $ (705) $ (3,121) $ 7,372 $ (719) $ 4,288 $11,855
======== ======== ======= ======== ======== =======
Basic income (loss) per common share........ $ (0.09) $ (0.22) $ 0.52 $ (0.05) $ 0.49 $ 1.36
======== ======== ======= ======== ======== =======
Diluted income (loss) per common share...... $ (0.09) $ (0.22) $ 0.35 $ (0.05) $ 0.47 $ 0.89
======== ======== ======= ======== ======== =======
Weighted average shares:
Basic(3).................................. 7,427 14,247 14,247 15,060 8,747 8,747
======== ======== ======= ======== ======== =======
Diluted(4)................................ 7,427 14,247 23,498 15,060 18,077 18,077
======== ======== ======= ======== ======== =======
Other Financial Data and Selected Ratios:
EBITDAX(5).................................. $ 992 $ 5,260 $47,359 $ 2,059 $ 17,202 $35,003
EBITDAX margin(6)........................... 50% 55% 60% 54% 57% 62%
Cash flows provided by (used in):
Operating activities...................... $ 8,044 $ (4,594) -- $ 5,165 $ 7,114 --
Investing activities...................... (27,081) (19,233) -- (10,001) (84,844) --
Financing activities...................... 19,689 45,457 -- 7,861 62,112 --
Capital and exploration expenditures........ $ 27,081 $ 20,803 -- $ 10,001 $121,454 --
</TABLE>

<TABLE>
<CAPTION>
AS OF JUNE 30,
-------------------------
AS OF DECEMBER 31, PRO FORMA
------------------ AS ADJUSTED
1998 1999 2000 2000(7)
------- ------- ----------- -----------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance Sheet Data:
Total assets.............................................. $40,015 $69,276 $163,841 $180,745
Long-term debt, excluding current maturities.............. 20,000 10,150 60,000 --
Redeemable preferred stock................................ -- 56,475 60,663 --
Stockholders' equity...................................... (694) (3,815) 863 153,430
</TABLE>

footnotes on the following page

6
<PAGE> 11

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

(1) Gives effect to the acquisitions and the disposition completed by us in
2000, each as if consummated on January 1, 1999.

(2) Net income (loss) available to common stockholders is computed by
subtracting preferred stock dividends and accretion of issuance costs for
the year ended December 31, 1999 of $836,342 and for the six months ended
June 30, 2000 of $4,232,583.

(3) Basic weighted average shares excludes 3,304,830 shares from the date placed
in escrow, November 17, 1999.

(4) Diluted weighted average shares includes the conversion of Class A and B
preferred stock.

(5) EBITDAX is defined as earnings before interest, taxes, depreciation,
depletion and amortization and exploration expenditures and is presented
because it is a widely accepted financial indication of an exploration and
production company's ability to service and incur debt. EBITDAX is not a
calculation based on generally accepted accounting principles and should not
be considered as an alternative to earnings (loss) as an indicator of the
company's operating performance or to cash flows as a measure of liquidity.
EBITDAX measures presented in this prospectus may not be comparable to other
similarly titled measures reported by other companies. In evaluating
EBITDAX, investors should consider, among other things, the amount by which
EBITDAX exceeds interest costs, how EBITDAX compares to principal repayments
on debt and how EBITDAX compares to capital expenditures for each period.

(6) Represents EBITDAX divided by revenue.

(7) As adjusted to give effect to the offering (at an assumed offering price of
$18.00 per share) and the application of the net offering proceeds described
in more detail under "Use of Proceeds."

ADDITIONAL PRO FORMA DATA

The net income (loss) data presented in the following table adjusts our
historical net income (loss) and our pro forma income giving effect to:

- the conversion of all outstanding shares of our preferred stock into
common stock as if the conversion had occurred on January 1, 1999;

- the release of 2,545,500 shares of common stock from escrow with an
expense of approximately $45.5 million as if the shares vested on January
1, 1999 and

- the use of a portion of the estimated net proceeds of this offering to
pay all outstanding indebtedness all as if the transaction had occurred
on January 1, 1999.

<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, 1999 JUNE 30, 2000
---------------------- ----------------------
HISTORICAL PRO FORMA HISTORICAL PRO FORMA
---------- --------- ---------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Pro forma income (loss)........................... $(45,674) $(27,415) $11,578 $20,878
======== ======== ======= =======
Pro forma basic and diluted income (loss) per
common share.................................... $ (1.86) (0.97) $ 0.47 $ 0.84
======== ======== ======= =======
Pro forma weighted average number of common shares
outstanding--basic and diluted.................. 24,573 28,239 24,789 24,789
======== ======== ======= =======
</TABLE>

7
<PAGE> 12

SUMMARY RESERVE AND OPERATING DATA

The following table presents summary information regarding our estimated
net proved oil and natural gas reserves as of December 31, 1998 and 1999 and
January 1, 2000 and our historical and pro forma operating data for the years
ended December 31, 1998 and 1999 and the six months ended June 30, 1999 and
2000. All calculations of estimated net proved reserves have been made in
accordance with the rules and regulations of the SEC, and, except as otherwise
indicated, give no effect to federal or state income taxes otherwise
attributable to estimated future net revenues for the sale of oil and natural
gas. The January 1, 2000 estimates of proved reserves are based on a reserve
report prepared by Netherland, Sewell, our independent petroleum engineering
consultants. Appendix A to this prospectus contains a letter prepared by
Netherland, Sewell summarizing the reserve report. For additional information
regarding our reserves, please read "Business and Properties -- Oil and Natural
Gas Reserves" and note 11 of the notes to our financial statements.

RESERVE DATA

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
------------------- JANUARY 1,
1998 1999 2000(4)
-------- -------- ----------
<S> <C> <C> <C>
Total estimated net proved reserves:
Oil (Mbbls)............................................... 2,861 3,824 28,040
Natural gas (Mmcf)........................................ 12,534 12,752 44,603
Total (Mboe)...................................... 4,950 5,949 35,474
Net proved developed reserves:
Oil (Mbbls)............................................... 2,467 2,715 24,991
Natural gas (Mmcf)........................................ 10,859 7,631 32,476
Total (Mboe)...................................... 4,277 3,987 30,404
Estimated future net revenues before income taxes (in
thousands)................................................ $41,051 $76,999 $326,416
Present value of estimated future net revenues before income
taxes (in thousands)(1)(2)................................ $27,533 $54,819 $258,525
Standardized measure of discounted future net cash flows (in
thousands)(3)............................................. $24,889 $47,177 $201,725
</TABLE>

table continued and footnotes on the following page

8
<PAGE> 13

OPERATING DATA

<TABLE>
<CAPTION>
PRO FORMA
JANUARY 29, 1998 PRO FORMA SIX MONTHS SIX MONTHS
(INCEPTION) TO YEAR ENDED YEAR ENDED ENDED JUNE 30, ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, ---------------- JUNE 30,
1998 1999 1999(6) 1999 2000 2000(6)
---------------- --------------- ------------ ------ ------- ------------
<S> <C> <C> <C> <C> <C> <C>
Net production:
Oil (Mbbls).............. 96 384 3,817 187 965 1,770
Natural gas (Mmcf)....... 238 831 7,430 325 1,479 2,880
Total (Mboe).......... 136 523 5,055 241 1,212 2,250
Net sales data (in
thousands):
Oil...................... $1,268 $6,678 $64,095 $2,613 $24,803 $47,091
Natural gas.............. 524 1,806 14,365 601 5,206 9,241
------ ------ ------- ------ ------- -------
Total................. $1,792 $8,484 $78,460 $3,214 $30,009 $56,332
====== ====== ======= ====== ======= =======
Average sales prices:
Oil (per Bbl)............ $13.21 $17.39 $ 16.79 $13.97 $ 25.70 $ 26.61
Natural gas (per Mcf).... 2.20 2.17 1.93 1.85 3.52 3.21
Total (per Boe)....... 13.18 16.22 15.52 13.34 24.76 25.04
Average (per Boe):
Lease operating
expense............... $ 2.64 $ 3.14 $ 5.40 $ 2.59 $ 6.60 $ 7.05
General and
administrative
expense............... 4.52 4.99 0.81 4.56 4.26 2.46
Depreciation, depletion
and amortization
expense............... 9.58 8.65 4.74 8.03 6.84 5.57
EBITDAX(5)............... 7.29 10.06 9.37 8.54 13.67 16.75
</TABLE>

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

(1) The present value of estimated future net revenues attributable to our
reserves was prepared using constant prices, as of the calculation date,
discounted at 10% per year on a pre-tax basis.

(2) The December 31, 1999 amount was calculated using a period end average
realized oil price of $24.64 per barrel and a period end average realized
gas price of $2.42 per Mcf.

(3) The standardized measure of discounted future net cash flows represents the
present value of future cash flows after income tax discounted at 10%.

(4) Includes reserves for East Bay and the additional interest acquired in South
Timbalier 26.

(6) The pro forma production amounts were obtained by aggregating the production
for the properties we acquired with our historical production. The pro forma
sales, expense and EBITDAX information per Boe was derived by dividing the
respective amounts from the unaudited pro forma financial statements
appearing elsewhere in this prospectus by the pro forma production.

9
<PAGE> 14

RISK FACTORS

You should carefully consider each of the risks described below, together
with all of the other information contained in this prospectus, before deciding
to invest in shares of our common stock. If any of the following risks develop
into actual events, our business, financial condition or results of operations
could be materially adversely affected, the trading price of your shares could
decline and you may lose all or part of your investment.

EXPLORING FOR AND PRODUCING OIL AND NATURAL GAS ARE HIGH-RISK ACTIVITIES WITH
MANY UNCERTAINTIES THAT COULD ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION
OR RESULTS OF OPERATIONS.

Our future success will depend on the success of our exploration and
production activities. Our oil and natural gas exploration and production
activities are subject to numerous risks beyond our control, including the risk
that drilling will not result in commercially viable oil or natural gas
production. Our decisions to purchase, explore, develop or otherwise exploit
prospects or properties will depend in part on the evaluation of data obtained
through geophysical and geological analyses, production data and engineering
studies, the results of which are often inconclusive or subject to varying
interpretations. Please read "-- Reserve estimates depend on many assumptions
that may turn out to be inaccurate" for a discussion of the uncertainty involved
in these processes. Our cost of drilling, completing and operating wells is
often uncertain before drilling commences. Overruns in budgeted expenditures are
common risks that can make a particular project uneconomical. Further, many
factors may curtail, delay or cancel drilling, including the following:

- pressure or irregularities in geological formations;

- shortages of or delays in obtaining equipment and qualified personnel;

- equipment failures or accidents;

- compliance with governmental requirements;

- adverse weather conditions, such as hurricanes and tropical storms;

- reductions in oil and natural gas prices;

- title problems; and

- limitations in the market for oil and natural gas.

WE MAY INCUR SUBSTANTIAL LOSSES AND BE SUBJECT TO SUBSTANTIAL LIABILITY CLAIMS
AS A RESULT OF OUR OPERATIONS.

Losses and liabilities arising from uninsured and underinsured events could
materially and adversely affect our business, financial condition or results of
operations. Our oil and natural gas exploration and production activities are
subject to all of the operating risks associated with drilling for and producing
oil and natural gas, including the possibility of:

- environmental hazards, such as uncontrollable flows of oil, natural gas,
brine, well fluids, toxic gas or other pollution into the environment,
including groundwater and shoreline contamination;

- abnormally pressured formations;

- mechanical difficulties, stuck oil field drilling and service tools and
casing collapse;

- fires and explosions;

- personal injuries and death; and

- natural disasters.

10
<PAGE> 15

Any of these risks could adversely affect our ability to conduct operations
or result in substantial losses to our company. We maintain insurance at levels
that we believe are consistent with industry practices, but we are not fully
insured against all risks. We may elect not to obtain insurance if we believe
that the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not
fully insurable. If a significant accident or other event occurs and is not
fully covered by insurance, it could adversely affect us.

A SUBSTANTIAL OR EXTENDED DECLINE IN OIL AND NATURAL GAS PRICES MAY ADVERSELY
AFFECT OUR BUSINESS, FINANCIAL CONDITION OR RESULTS OF OPERATIONS AND OUR
ABILITY TO MEET OUR CAPITAL EXPENDITURE OBLIGATIONS AND FINANCIAL COMMITMENTS.

The price we receive for our oil and natural gas production heavily
influences our revenue, profitability, access to capital and future rate of
growth. Oil and natural gas are commodities and, therefore, their prices are
subject to wide fluctuations in response to relatively minor changes in supply
and demand. Historically, the markets for oil and natural gas have been
volatile. These markets will likely continue to be volatile in the future. The
prices we receive for our production, and the levels of our production, depend
on numerous factors beyond our control. These factors include:

- changes in global supply of and demand for oil and natural gas;

- the actions of the Organization of Petroleum Exporting Countries, or
OPEC;

- worldwide economic conditions, which affect worldwide demand for energy;

- the price and quantity of foreign imports;

- political conditions, including embargoes, in or affecting other
oil-producing countries;

- the level of worldwide exploration and production activity;

- the level of global oil and natural gas inventories;

- weather conditions;

- interest rates and the cost of capital;

- technological advances affecting energy consumption;

- domestic and foreign government regulation, legislation and policies; and

- the price and availability of alternative fuels.

The prices of oil and natural gas may decline. Lower oil and natural gas
prices may not only decrease our revenues on a per unit basis but also may
reduce the amount of oil and natural gas that we can produce economically. A
substantial or extended decline in oil and natural gas prices may materially and
adversely affect our future business, financial condition, results of
operations, liquidity or ability to finance planned capital expenditures.
Further, oil prices and natural gas prices do not necessarily move together.
Because approximately 79% of our estimated proved reserves as of January 1, 2000
were oil reserves, our financial results are more sensitive to movements in oil
prices.

OUR LIMITED OPERATING HISTORY MAKES EVALUATING OUR BUSINESS DIFFICULT. WE HAVE
INCURRED LOSSES IN RECENT PERIODS AND MAY INCUR LOSSES IN THE FUTURE. IF WE FAIL
TO ACHIEVE OR SUSTAIN PROFITABILITY IN THE FUTURE, THE MARKET PRICE OF OUR
COMMON STOCK COULD BE ADVERSELY AFFECTED.

We have only a limited operating history upon which you can evaluate our
business and prospects. Because of our limited operating history, our future
results of operations are difficult to estimate accurately. We have also
recently completed two acquisitions which have significantly changed our
company.

11
<PAGE> 16

We incurred historical net losses of $2.3 million in 1999 and $.7 million
in 1998. In considering whether to invest in our common stock, you should
consider our historical financial results and the factors that caused those
results. Please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations." If we fail to achieve or sustain
profitability in the future, the market price of our common stock could be
adversely affected. If we do achieve profitability in any period, we may be
unable to sustain or increase such profitability on a quarterly or annual basis.

WE MAY INCUR WRITE-DOWNS OF THE CARRYING VALUES OF OUR PROPERTIES.

Accounting rules require that we review periodically the carrying value of
our oil and natural gas properties for possible impairment. Based on specific
market factors and circumstances at the time of prospective impairment reviews,
and the continuing evaluation of development plans, production data, economics
and other factors, we may be required to write down the carrying value of our
oil and natural gas properties. A write-down constitutes a non-cash charge to
earnings, which reduces our equity. We may incur impairment charges in the
future, which could have a material adverse effect on our results of operations
in the period taken.

RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY TURN OUT TO BE INACCURATE.
ANY MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS
WILL MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES.

The process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant inaccuracies
in these interpretations or assumptions could materially affect the estimated
quantities and present value of reserves shown in this prospectus. Please read
"Business and Properties -- Oil and Natural Gas Reserves" for information about
our oil and natural gas reserves.

In order to prepare our estimates we must project production rates and
timing of development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and
present value of reserves shown in this prospectus. In addition, we may adjust
estimates of proved reserves to reflect production history, results of
exploration and development, prevailing oil and natural gas prices and other
factors, many of which are beyond our control. At January 1, 2000, with the
inclusion of our East Bay and South Timbalier Block 26 transactions, 51% of our
proved reserves were either proved undeveloped or proved non-producing.

You should not assume that the present value of future net revenues from
our proved reserves referred to in this prospectus is the current market value
of our estimated oil and natural gas reserves. In accordance with SEC
requirements, we generally base the estimated discounted future net cash flows
from our proved reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in the present
value estimate.

A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
IN ONE PROPERTY. BECAUSE OF THIS CONCENTRATION, ANY PRODUCTION PROBLEMS OR
INACCURACIES IN RESERVE ESTIMATES RELATED TO THIS PROPERTY COULD IMPACT OUR
BUSINESS ADVERSELY.

During the month of June 2000, 73% of our daily production came from our
East Bay field. If mechanical problems, storms or other events curtail a
substantial portion of this production, our cash flow would be affected
adversely. Also, at January 1, 2000, approximately 77% of our proved reserves
were

12
<PAGE> 17

located on this property. If the actual reserves associated with this property
are less than our estimated reserves, our business, financial condition or
results of operations could be adversely affected.

UNLESS WE REPLACE OUR OIL AND NATURAL GAS RESERVES, OUR RESERVES AND PRODUCTION
WILL DECLINE, WHICH WOULD ADVERSELY AFFECT OUR CASH FLOWS AND INCOME.

Unless we conduct successful development, exploitation or exploration
activities or acquire properties containing proved reserves, our proved reserves
will decline as those reserves are produced. Producing oil and natural gas
reservoirs generally are characterized by declining production rates that vary
depending upon reservoir characteristics and other factors. Our future oil and
natural gas reserves and production, and, therefore, our cash flow and income,
are highly dependent on our success in efficiently developing and exploiting our
current reserves and economically finding or acquiring additional recoverable
reserves. We cannot assure you that we will be able to develop, exploit, find or
acquire additional reserves to replace our current and future production.

RELATIVELY SHORT PRODUCTION PERIODS FOR GULF OF MEXICO PROPERTIES SUBJECT US TO
HIGHER RESERVE REPLACEMENT NEEDS.

All of our operations are in the Gulf of Mexico Shelf. Production of
reserves from reservoirs in the Gulf of Mexico generally declines more rapidly
than from reservoirs in many other producing regions of the world. High
production rates generally result in recovery of a relatively higher percentage
of reserves from properties during the initial few years of production, and, as
a result, our reserve replacement needs from new investments are relatively
greater. Also, our revenues and return on capital will depend significantly on
prices prevailing during these relatively short production periods.

RAPID GROWTH MAY PLACE SIGNIFICANT DEMANDS ON OUR RESOURCES.

We have experienced rapid growth in our operations and expect that
significant expansion of our operations will continue. Our rapid growth has
placed, and our anticipated future growth will continue to place, a significant
demand on our managerial, operational and financial resources due to:

- the need to manage relationships with various strategic partners and
other third parties;

- difficulties in hiring and retaining skilled personnel necessary to
support our business;

- the need to train and manage a growing employee base; and

- pressures for the continued development of our financial and information
management systems.

If we have not made adequate allowances for the costs and risks associated
with this expansion or if our systems, procedures or controls are not adequate
to support our operations, our business could be harmed.

PROPERTIES THAT WE BUY MAY NOT PRODUCE AS PROJECTED, AND WE MAY BE UNABLE TO
IDENTIFY LIABILITIES ASSOCIATED WITH THE PROPERTIES OR OBTAIN PROTECTION FROM
SELLERS AGAINST THEM.

Our strategy includes acquisitions. The successful acquisition of producing
properties requires assessments of many factors, which are inherently inexact
and may be inaccurate, including:

- the amount of recoverable reserves;

- future oil and natural gas prices;

- estimates of operating costs;

- estimates of future development costs;

- estimates of the costs and timing of plugging and abandonment; and

- potential environmental and other liabilities.
13
<PAGE> 18

Our assessment will not reveal all existing or potential problems, nor will
it permit us to become familiar enough with the properties to assess fully their
deficiencies and capabilities. In the course of our due diligence, we may not
inspect every well, platform or pipeline. We cannot necessarily observe
structural and environmental problems, such as pipeline corrosion or groundwater
contamination, when an inspection is made. We may not be able to obtain
contractual indemnities from the seller for liabilities that it created. We may
be required to assume the risk of the physical condition of the properties in
addition to the risk that the properties may not perform in accordance with our
expectations.

SUBSTANTIAL ACQUISITIONS, DRILL-TO-EARN PROGRAMS OR OTHER TRANSACTIONS COULD
REQUIRE SIGNIFICANT EXTERNAL CAPITAL AND COULD CHANGE OUR RISK AND PROPERTY
PROFILE.

In order to finance acquisitions of additional producing properties or
enter into significant drill-to-earn programs, we may need to alter or increase
our capitalization substantially through the issuance of debt or equity
securities, the sale of production payments or other means. These changes in
capitalization may significantly affect our risk profile. Additionally,
significant acquisitions, drill-to-earn programs or other transactions can
change the character of our operations and business. The character of the new
properties may be substantially different in operating or geological
characteristics or geographic location than our existing properties.
Furthermore, we may not be able to obtain external funding for any such
acquisitions, drill-to-earn programs or other transactions or to obtain external
funding on terms acceptable to us.

OUR PRINCIPAL STOCKHOLDER IS IN A POSITION TO AFFECT OUR ONGOING OPERATIONS,
CORPORATE TRANSACTIONS AND OTHER MATTERS.

After giving effect to this offering, our principal stockholder, Evercore,
together with its affiliates, will beneficially own approximately 34.8% of our
outstanding shares of common stock and, assuming the exercise in full of the
underwriters' options to purchase additional shares, will beneficially own
approximately 33.7% of our outstanding shares of common stock. Evercore is
entitled to nominate four of our eight directors. Evercore's consent is required
to take a number of corporate actions, including making acquisitions, selling
assets, adopting or amending capital and operating budgets, incurring
indebtedness, increasing compensation, issuing our stock, declaring dividends,
engaging in hedging transactions and entering joint ventures, and Evercore may
terminate the employment of Mr. Bachmann, our chairman, president and chief
executive officer. As a result, Evercore is in a position to control or
influence substantially the manner in which our business is operated and the
outcome of stockholder votes on the election of directors and other matters.
Please read "Certain Transactions -- Agreements Related to the Evercore
Investment."

THE LOSS OF RICHARD A. BACHMANN, SENIOR MANAGEMENT OR TECHNICAL PERSONNEL COULD
ADVERSELY AFFECT US.

To a large extent, we depend on the services of our founder and chairman,
president and chief executive officer, Richard A. Bachmann, and other senior
management personnel. The loss of the services of Mr. Bachmann or other senior
management personnel could have a material adverse effect on our operations. We
do not maintain any insurance against the loss of any of these individuals.

The Gulf of Mexico area is highly competitive, and our success there will
depend on our ability to attract and retain experienced geoscientists and other
professional staff. As of June 30, 2000, we have 22 geoscientists and engineers
who are experienced in Gulf of Mexico operations. Loss of these experienced
personnel could have a material adverse impact on our ability to compete in this
area.

THE UNAVAILABILITY OR HIGH COST OF ADDITIONAL DRILLING RIGS, EQUIPMENT,
SUPPLIES, PERSONNEL AND OILFIELD SERVICES COULD ADVERSELY AFFECT OUR ABILITY TO
EXECUTE ON A TIMELY BASIS OUR EXPLORATION AND DEVELOPMENT PLANS WITHIN OUR
BUDGET.

All of our operations are in the Gulf of Mexico Shelf. Shortages or the
high cost of drilling rigs, equipment, supplies or personnel could delay or
adversely affect our development and exploration operations, which could have a
material adverse effect on our business, financial condition or results of
operations. Recently, drilling activity in the Gulf of Mexico has increased, and
we have experienced

14
<PAGE> 19

increases in associated costs, including those related to drilling rigs,
equipment, supplies and personnel and the services and products of other vendors
to the industry. Increased drilling activity in the Gulf of Mexico also
decreases the availability of offshore rigs. We cannot assure you that costs
will not increase further or that necessary equipment and services will be
available to us at economical prices.

MARKET CONDITIONS OR OPERATIONAL IMPEDIMENTS MAY HINDER OUR ACCESS TO OIL AND
NATURAL GAS MARKETS OR DELAY OUR PRODUCTION.

Market conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines and
processing facilities owned and operated by third parties. Our failure to obtain
such services on acceptable terms could materially harm our business. We may be
required to shut in wells for lack of a market or because of inadequacy or
unavailability of natural gas pipeline or gathering system capacity. If that
were to occur, we would be unable to realize revenue from those wells until
production arrangements were made to deliver to market.

COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY IS INTENSE, WHICH MAY ADVERSELY
AFFECT OUR ABILITY TO COMPETE.

We operate in a highly competitive environment for acquiring properties,
marketing oil and natural gas and securing trained personnel. Many of our
competitors possess and employ financial, technical and personnel resources
substantially greater than ours, which can be particularly important in Gulf of
Mexico activities. Those companies may be able to pay more for productive oil
and natural gas properties and exploratory prospects and to evaluate, bid for
and purchase a greater number of properties and prospects than our financial or
personnel resources permit. Our ability to acquire additional prospects and to
find and develop reserves in the future will depend on our ability to evaluate
and select suitable properties and to consummate transactions in a highly
competitive environment. Also, there is substantial competition for capital
available for investment in the oil and natural gas industry. We cannot assure
you that we will be able to compete successfully in the future in acquiring
prospective reserves, developing reserves, marketing hydrocarbons, attracting
and retaining quality personnel and raising additional capital.

GOVERNMENT LAWS AND REGULATIONS CAN ADVERSELY AFFECT OUR OPERATIONS.

Development, production and sale of oil and natural gas are subject to
extensive federal, state and local environmental and other governmental
regulation. We have made and will continue to make expenditures to comply with
environmental and other governmental regulations. These regulations could change
in ways that might substantially increase our costs. Offshore operations are
subject to more extensive governmental regulation than onshore operations.
Please read "Business and Properties -- Regulation" for an additional discussion
of government regulations that affect us.

OUR HEDGING TRANSACTIONS COULD RESULT IN LOSSES OR LIMIT OUR POTENTIAL GAINS.

15
<PAGE> 20

contract defaults on its obligations or there is a change in the expected
differential between the underlying price in the hedging agreement and actual
prices received. Hedging transactions may limit the benefit we would have
otherwise received from increases in the prices for oil and natural gas.
Furthermore, if we do not engage in hedging transactions, we may be more
adversely affected by declines in oil and natural gas prices than our
competitors who engage in hedging transactions. Additionally, hedging
transactions may expose us to cash margin requirements.

THE MARKET PRICE OF OUR COMMON STOCK COULD BE ADVERSELY AFFECTED BY SALES OF
SUBSTANTIAL AMOUNTS OF OUR COMMON STOCK IN THE PUBLIC MARKETS.

Sales by Evercore, Energy Income Fund and other stockholders of a
substantial number of shares of our common stock in the public markets following
this offering, or the perception that such sales might occur, could have a
material adverse effect on the price of our common stock or could impair our
ability to obtain capital through an offering of equity securities. Please read
"Shares Eligible for Future Sale."

PROVISIONS IN OUR ORGANIZATIONAL DOCUMENTS AND UNDER DELAWARE LAW COULD DELAY OR
PREVENT A CHANGE IN CONTROL OF OUR COMPANY, WHICH COULD ADVERSELY AFFECT THE
PRICE OF OUR COMMON STOCK.

The existence of some provisions in our organizational documents and under
Delaware law could delay or prevent a change in control of our company, which
could adversely affect the price of our common stock. The provisions in our
certificate of incorporation and bylaws that could delay or prevent an
unsolicited change in control of our company include:

- the board of directors' ability to issue shares of preferred stock and
determine the terms of the preferred stock without stockholder approval;
and

- a prohibition on the right of stockholders to call meetings and a
limitation on the right of stockholders to act by written consent and to
present proposals or make nominations at stockholder meetings.

In addition, Delaware law imposes some restrictions on mergers and other
business combinations between us and any holder of 15% or more of our
outstanding common stock. Evercore is generally exempted from these provisions
and will have special rights so long as it owns at least a majority of our
outstanding common stock.

INVESTORS IN THIS OFFERING WILL SUFFER IMMEDIATE AND SUBSTANTIAL DILUTION.

The initial public offering price of our common stock will be substantially
higher than the pro forma net tangible book value per share of our common stock.
As of June 30, 2000, our net tangible book value was $58.4 million, or $2.74 per
share of our common stock. After giving effect to the sale of 5,750,000 shares
of common stock in this offering and after deducting underwriting discounts and
commissions and estimated offering expenses, our net tangible book value as of
June 30, 2000 would have been $153.4 million, or $5.67 per share of our common
stock. This represents an immediate increase in our net tangible book value of
$2.93 per share to current stockholders and an immediate dilution of $12.33 per
share to new investors purchasing our common stock in this offering. Please read
"Dilution."

WE HAVE NO PLANS TO PAY DIVIDENDS ON OUR COMMON STOCK. YOU MAY NOT RECEIVE FUNDS
WITHOUT SELLING YOUR SHARES.

We have never declared or paid cash dividends on our common stock and do
not anticipate paying any cash dividends on our common stock in the foreseeable
future. We currently intend to retain future earnings, if any, to finance the
expansion of our business. Our future dividend policy is within the discretion
of our board of directors and will depend upon various factors, including our
business, financial condition, results of operations, capital requirements and
investment opportunities.

16
<PAGE> 21

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a
number of risks and uncertainties, many of which are beyond our control, which
may include statements about our:

- business strategy;

- reserves;

- technology;

- financial strategy;

- realized oil and natural gas prices;

- production;

- uncertainty regarding our future operating results; and

- plans, objectives, expectations and intentions contained in this
prospectus that are not historical.

All statements, other than statements of historical fact included in this
prospectus, regarding our strategy, future operations, financial position,
estimated revenues and losses, projected costs, prospects, plans and objectives
of management are forward-looking statements. When used in this prospectus, the
words "will," "could," "believe," "anticipate," "intend," "estimate," "expect,"
"project" and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain such identifying
words. All forward-looking statements speak only as of the date of this
prospectus. You should not place undue reliance on these forward-looking
statements. Although we believe that our plans, intentions and expectations
reflected in or suggested by the forward-looking statements we make in this
prospectus are reasonable, we can give no assurance that these plans, intentions
or expectations will be achieved. We disclose important factors that could cause
our actual results to differ materially from our expectations under "Risk
Factors," "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and elsewhere in this prospectus. These cautionary
statements qualify all forward-looking statements attributable to us or persons
acting on our behalf.

17
<PAGE> 22

USE OF PROCEEDS

We estimate that we will receive net proceeds of approximately $95.1
million from the sale of the 5,750,000 shares of our common stock in this
offering, based upon an assumed initial public offering price of $18.00 per
share, the midpoint of the offering range, and after deducting underwriting
discounts and commissions and estimated offering expenses. If the underwriters'
over-allotment options are exercised in full, we estimate that our net proceeds
will be approximately $109.5 million.

We generally intend to use the net proceeds from this offering as follows:

- To repay indebtedness under our financing agreement with Energy Income
Fund, L.P. ($10.0 million at August 31, 2000) and indebtedness under our
reducing revolving credit facility with Bank One, Texas, N.A. ($64.1
million at August 31, 2000). The indebtedness under our financing
agreement with Energy Income Fund bears interest at a rate equal to 13%
through September 30, 2000, 14% through December 31, 2000 and 15%
thereafter and matures on July 1, 2001. At June 30, 2000, the interest
rate on the indebtedness under our reducing revolving credit facility
with Bank One was 10.589%. A portion of the Bank One indebtedness matures
on March 30, 2001 and the remainder matures on March 30, 2003. The
proceeds from the Bank One credit facility were used to acquire the East
Bay field and the increased interest in South Timbalier 26 and for
working capital purposes.

- To redeem $4.5 million liquidation preference of our Series C preferred
stock, assuming the offering is consummated on September 30, 2000.

- For general corporate purposes, including expanding our drilling program,
working capital and acquisitions. Please read "Management's Discussion
and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" for a discussion of how we
expect to finance our ongoing operations.

The amounts and timing of some of these expenditures will vary
significantly depending on a number of factors, including, but not limited to,
the amount of cash generated by our operations and other factors described under
"Risk Factors."

We intend to invest the net proceeds from this offering in short-term
interest-bearing investment grade securities pending the uses described above.

DIVIDEND POLICY

We have never declared or paid cash dividends on our common stock and do
not anticipate paying any cash dividends on our common stock in the foreseeable
future. We currently intend to retain future earnings, if any, to finance the
expansion of our business. Our future dividend policy is within the discretion
of our board of directors and will depend upon various factors, including our
results of operations, financial condition, capital requirements and investment
opportunities. In addition, the consent of Evercore is required to pay
dividends.

18
<PAGE> 23

CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2000:

- on an actual basis; and

- on an as adjusted basis to give effect to the sale of the shares of our
common stock in this offering and the anticipated use of the estimated
net proceeds. Please read "Use of Proceeds."

The as adjusted column of this table includes the following shares which
will be outstanding upon completion of this offering:

- 9,329,839 shares of our common stock issuable on conversion of our Series
A preferred stock and Series B preferred stock, assuming an offering date
of June 30, 2000;

- 928,050 shares of our common stock issuable on exercise of a warrant held
by Energy Income Fund; and

- 10,650 shares of our common stock that will be issued as described under
"Certain Transactions -- Agreements Related to the Evercore
Investment -- Stockholder Agreement -- Escrowed and Bonus Shares."

The as adjusted column excludes 759,330 shares held in escrow that will be
cancelled upon consummation of this offering.

You should read this table in conjunction with our financial statements and
the notes to those financial statements included elsewhere in this prospectus.

<TABLE>
<CAPTION>
AS OF JUNE 30, 2000
----------------------
PRO FORMA
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents(1)................................ $ 6,664 $ 23,568
======== ========
Long-term debt, including current maturities................ $ 75,000 $ --
Redeemable preferred stock: par value $1.00 per share;
1,700,000 shares authorized; 600,000 shares issued and
outstanding actual;
no shares issued and outstanding as adjusted(1)........... 60,663 --
Stockholders' equity:
Common stock: par value $0.01 per share; 50,000,000 shares
authorized;
11,798,280 shares issued and outstanding actual;
27,057,489 shares issued and outstanding as adjusted...... 118 271
Additional paid-in capital.................................. 422 152,836
Retained earnings........................................... 323 323
-------- --------
Total stockholders' equity............................. 863 153,430
-------- --------
Total capitalization.............................. $136,526 $153,430
======== ========
</TABLE>

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

(1) Assuming an offering date of June 30, 2000, approximately $3,151,000
liquidation preference of Series C preferred stock will be issued
immediately prior to the completion of this offering when our board of
directors declares accrued and unpaid dividends of our Series A preferred
stock. See note 4 to our financial statements for a description of our
preferred stock. We will immediately redeem the Series C preferred stock
with a portion of the proceeds of this offering.

19
<PAGE> 24

DILUTION

The net tangible book value per share of our common stock is the difference
between our tangible assets and our liabilities, divided by the number of shares
of common stock outstanding upon completion of this offering. For purchasers of
our common stock in this offering, dilution in net tangible book value per share
represents the difference between the initial public offering price of our
common stock in this offering and the net tangible book value of our common
stock immediately after completing this offering.

As of June 30, 2000, our net tangible book value was $58.4 million, or
$2.74 per share of our common stock. After giving effect to the sale of
5,750,000 shares of common stock in this offering at an assumed initial public
offering price of $18.00 per share, the midpoint of the offering range, and
after deducting underwriting discounts and commissions and estimated offering
expenses, our net tangible book value as of June 30, 2000 would have been $153.4
million, or $5.67 per share of our common stock. This represents an immediate
increase in our net tangible book value of $2.93 per share to current
stockholders and an immediate dilution of $12.33 per share to new investors
purchasing our common stock in this offering. The following table illustrates
the foregoing information as of June 30, 2000 with respect to dilution to new
investors:

<TABLE>
<S> <C> <C>
Assumed initial public offering price per share............. $18.00
Net tangible book value per share at June 30, 2000........ $2.74
Increase in net tangible book value per share attributable
to new investors....................................... 2.93
-----
Net tangible book value per share after offering............ 5.67
------
Dilution per share to new investors......................... $12.33
======
</TABLE>

The following table summarizes, as of June 30, 2000, the differences
between the total number of shares of our common stock purchased from us, the
total consideration paid and the average price per share paid by existing
stockholders and new investors purchasing shares of our common stock in this
offering:

<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION
--------------------- ---------------------- AVERAGE PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
----------- ------- ------------ ------- -------------
<S> <C> <C> <C> <C> <C>
Existing stockholders................ 21,307,489 78.7% $ 60,010,040 36.7% $ 2.82
New investors........................ 5,750,000 21.3 103,500,000 63.3 18.00
----------- ----- ------------ ------
Total...................... 27,057,489 100.0% 163,510,040 100.0%
=========== ===== ============ ======
</TABLE>

The foregoing discussion and tables give effect to the Energy Income Fund
warrant and the conversion of our Series A and B preferred stock into common
stock upon completion of this offering. Please read "Capitalization."

If the underwriters' over-allotment options are exercised in full, the
number of shares held by new investors will be increased to 6,612,500, or
approximately 23.7% of the total number of shares of our common stock.

20
<PAGE> 25

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth our selected historical financial data as of
and for each of the periods indicated. The statement of operations data for the
period January 29, 1998 (inception) to December 31, 1998 and for the year ended
December 31, 1999 and the balance sheet data as of December 31, 1998 and 1999
were derived from our audited financial statements included in this prospectus.
The historical financial data as of June 30, 2000 and for the six-month period
ended June 30, 1999 and 2000 were derived from our unaudited financial
statements which, in our opinion, include all adjustments (which consist only of
normal recurring adjustments) necessary for a fair presentation of our financial
condition and results of operations for such interim periods. The following
information should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and our financial
statements and the related notes thereto included elsewhere in this prospectus.

<TABLE>
<CAPTION>
JANUARY 29,
1998 SIX MONTHS ENDED
(INCEPTION) TO YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, --------------------
1998 1999 1999 2000
-------------- ------------ -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Statement of Operations Data:
Revenue............................................ $ 1,966 $ 9,509 $ 3,780 $ 30,356
-------- -------- -------- --------
Costs and expenses:
Lease operating.................................. 359 1,640 623 7,992
Exploration expenditures and dry hole costs...... -- 1,570 -- 824
Depreciation, depletion and amortization......... 1,303 4,525 1,936 8,286
General and administrative....................... 615 2,609 1,098 5,162
-------- -------- -------- --------
Total costs and expenses.................... 2,277 10,344 3,657 22,264
-------- -------- -------- --------
Income (loss) from operations...................... (311) (835) 123 8,092
-------- -------- -------- --------
Interest income.................................... 49 312 85 328
Interest expense................................... (802) (2,947) (1,301) (3,057)
Gain on sale of oil and gas properties............. -- -- -- 7,781
-------- -------- -------- --------
Income (loss) before income taxes.................. (1,064) (3,470) (1,093) 13,144
Income taxes....................................... 359 1,185 374 (4,623)
-------- -------- -------- --------
Net income (loss).................................. $ (705) $ (2,285) $ (719) $ 8,521
======== ======== ======== ========
Net income (loss) available to common
stockholders(1).................................. $ (705) $ (3,121) $ (719) $ 4,288
======== ======== ======== ========
Basic net income (loss) per common share........... $ (0.09) $ (0.22) $ (0.05) $ 0.49
======== ======== ======== ========
Diluted net income (loss) per common share......... $ (0.09) $ (0.22) $ (0.05) $ 0.47
======== ======== ======== ========
Other Financial Data and Selected Ratios:
EBITDAX(2)......................................... $ 992 $ 5,260 $ 2,059 $ 17,202
EBITDAX margin(3).................................. 50% 55% 54% 57%
Cash flows provided by (used in):
Operating activities............................. $ 8,044 $ (4,594) $ 5,165 $ 7,114
Investing activities............................. (27,081) (19,233) (10,001) (84,844)
Financing activities............................. 19,689 45,457 7,861 62,112
Capital and exploration expenditures............... $ 27,081 $ 20,803 $ 10,001 $121,454
</TABLE>

table continued and footnotes on the following page

21
<PAGE> 26

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
------------------ JUNE 30,
1998 1999 2000
------- ------- -----------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
Balance Sheet Data:
Total assets.............................................. $40,015 $69,276 $163,841
Long-term debt, excluding current maturities.............. 20,000 10,150 60,000
Redeemable preferred stock................................ -- 56,475 60,663
Stockholders' equity...................................... (694) (3,815) 863
</TABLE>

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

(1) Net loss available to common stockholders is computed by subtracting
preferred stock dividends and accretion of issuance costs for the year ended
December 31, 1999 of $836,342 and for the six months ended June 30, 2000 of
$4,232,583.

(2) EBITDAX is defined as earnings before interest, taxes, depreciation,
depletion and amortization and exploration expenditures and is presented
because it is a widely accepted financial indication of an exploration and
production company's ability to service and incur debt. EBITDAX is not a
calculation based on generally accepted accounting principles and should not
be considered as an alternative to earnings (loss) as an indicator of the
company's operating performance or to cash flows as a measure of liquidity.
EBITDAX measures presented in this prospectus may not be comparable to other
similarly titled measures reported by other companies. In evaluating
EBITDAX, investors should consider, among other things, the amount by which
EBITDAX exceeds interest costs, how EBITDAX compares to principal repayments
on debt and how EBITDAX compares to capital expenditures for each period.

(3) Represents EBITDAX divided by revenue.

ADDITIONAL PRO FORMA DATA

The net income (loss) data presented in the following table adjusts our
historical net income (loss) and our pro forma income giving effect to:

- the conversion of all outstanding shares of our preferred stock into
common stock as if the conversion had occurred on January 1, 1999;

- the release of 2,545,500 shares of common stock from escrow with an
expense of approximately $45.5 million as if the shares vested on January
1, 1999 and

- the use of a portion of the estimated net proceeds of this offering to
pay all outstanding indebtedness all as if the transaction had occurred
on January 1, 1999.

22
<PAGE> 27

UNAUDITED PRO FORMA FINANCIAL INFORMATION

On March 31, 2000, we acquired Unocal's 80% interest in South Timbalier 26.
In April 2000, we sold to Vastar 50% of our working interest in South Timbalier
26. The unaudited pro forma financial information reflects the net 30% interest
acquired in South Timbalier 26. Additionally, on March 31, 2000, we closed the
purchase of an average 98.5% working interest in the East Bay field from Ocean
Energy for $72.6 million. Adjustments have been made to reflect the financial
impact of purchase accounting and other items had the acquisitions taken place
on January 1, 1999 with respect to operating data. The historical operations for
East Bay field and South Timbalier 26 are included in the historical EPL amounts
from March 31, 2000, their date of acquisition. The pro forma adjustments are
described in the accompanying notes and are based on preliminary estimates and
certain assumptions we believe are reasonable under the circumstances. In the
purchases and the sale of the properties, the respective buyers have the right
to audit the closing statements. We do not expect any material adjustments as a
result of these audits.

The unaudited pro forma financial information is for comparative purposes
only and does not purport to be indicative of the results which would actually
have been obtained had the acquisitions been effected on the pro forma dates, or
of the results which may be obtained in the future. The unaudited pro forma
financial information in our opinion reflects all adjustments necessary to
present fairly the data for such periods.

The unaudited pro forma financial information should be read in conjunction
with the historical financial statements appearing elsewhere in this prospectus.

23
<PAGE> 28

ENERGY PARTNERS, LTD.

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2000

<TABLE>
<CAPTION>
PRO FORMA
ADJUSTMENTS
HISTORICAL -------------------
HISTORICAL HISTORICAL SOUTH
EPL EAST BAY TIMBALIER 26 PRO FORMA
---------- ---------- ------------ ----------
(UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenue
Oil and gas............... $ 30,009 $23,137 $3,186 $ 56,332
Other..................... 347 -- -- (a) (278) 69
---------- ------- ------ ----------
30,356 23,137 3,186 56,401
Costs and expenses:
Lease operating........... 7,992 7,245 736 (a) (104) 15,869
Exploration expenditures
and dry hole costs..... 824 -- -- 824
Depreciation, depletion
and amortization....... 8,286 -- -- (b) 4,245 12,531
General and
administrative......... 5,162 -- -- (c) 367 5,529
---------- ------- ------ ----------
Total costs and
expenses........ 22,264 7,245 736 34,753
---------- ------- ------ ----------
Income from operations...... 8,092 15,892 2,450 21,648
Other income (expense):
Interest income........... 328 -- -- 328
Interest expense.......... (3,057) -- -- (d) (1,733) (4,790)
Gain on sale of petroleum
assets................. 7,781 7,781
---------- ------- ------ ----------
5,052 -- -- 3,319
Income before
income taxes.... 13,144 15,892 2,450 24,967
Income taxes................ 4,623 -- -- (e) (4,256) (8,879)
---------- ------- ------ ----------
Net income........ $ 8,521 $15,892 $2,450 $ 16,088
========== ======= ====== ==========
Basic income per common
share and common share
equivalent................ $ 0.49 $ 1.36
========== ==========
Basic weighted average
shares outstanding........ 8,747,000 (f) 8,747,000
========== ==========
Diluted income per common
share and common share
equivalent................ $ 0.47 $ 0.89
========== ==========
Diluted weighted average
shares outstanding........ 18,076,839 (f) 18,076,839
========== ==========
</TABLE>

See notes to unaudited pro forma financial information

24
<PAGE> 29

ENERGY PARTNERS, LTD.

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999

<TABLE>
<CAPTION>
HISTORICAL
HISTORICAL HISTORICAL SOUTH PRO FORMA
EPL EAST BAY TIMBALIER 26 ADJUSTMENTS PRO FORMA
---------- ---------- ------------ ------------ ----------
(UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenue
Oil and gas................. $ 8,484 $62,027 $7,949 $ 78,460
Other....................... 1,025 -- -- (a) (766) 259
---------- ------- ------ ----------
9,509 62,027 7,949 78,719
Costs and expenses:
Lease operating............. 1,640 24,182 1,748 (a) (287) 27,283
Exploration expenditures and
dry hole costs........... 1,570 -- -- 1,570
Depreciation, depletion and
amortization............. 4,525 -- -- (b) 18,775 23,300
General and
administrative........... 2,609 -- -- (c) 1,468 4,077
---------- ------- ------ ----------
Total costs and
expenses.......... 10,344 24,182 1,748 56,230
---------- ------- ------ ----------
Income (loss) from
operations.................. (835) 37,845 6,201 22,489
Other income (expense):
Interest income............. 312 -- -- 312
Interest expense............ (2,947) -- -- (d) (6,930) (9,877)
---------- ------- ------ ----------
(2,635) -- -- (9,565)
Income (loss) before
income taxes...... (3,470) 37,845 6,201 12,924
Income taxes.................. 1,186 -- -- (e) (5,902) (4,716)
---------- ------- ------ ----------
Net income (loss)... $ (2,284) $37,845 $6,201 $ 8,208
========== ======= ====== ==========
Basic (loss) income per common
share and common share
equivalent.................. $ (0.22) $ 0.52
========== ==========
Basic weighted average shares
outstanding................. 14,246,727 (f) 14,246,727
========== ==========
Diluted (loss) income per
common share and common
share equivalent............ $ (0.22) $ 0.35
========== ==========
Diluted weighted average
shares outstanding.......... 14,246,727 (f) 23,498,009
========== ==========
</TABLE>

See notes to unaudited pro forma financial information

25
<PAGE> 30

ENERGY PARTNERS, LTD.

NOTES TO UNAUDITED PRO FORMA FINANCIAL INFORMATION

(a) Under the operating agreement with Unocal, we received a management fee for
operating South Timbalier 26 of $.8 million in 1999 and $.3 million in the
quarter ended March 31, 2000. We no longer received this revenue after
March 31, 2000. Historical South Timbalier 26 lease operating expense
includes corresponding expenses of $.3 million in 1999 and $.1 million in
the quarter ended March 31, 2000.

(b) To adjust depreciation, depletion and amortization amounts on a historical
basis to amounts that would have been included in the financial statements
effective January 1, 1999.

(c) To adjust general and administrative expense to reflect the expenses we
incurred for salaries of technical personnel and additional office space
for these employees which were a direct result of the East Bay acquisition.
We would have incurred these costs if East Bay had been purchased on
January 1, 1999.

(d) To record interest expense on $66.0 million at the current interest rate of
10.5% for the acquisitions. If the interest rate would have fluctuated
1/8%, the annual interest would have increased/decreased by $.08 million
and $.02 million for the year ended December 31, 1999 and the six months
ended June 30, 2000, respectively.

(e) To record the provision for federal and state income taxes at a corporate
statutory rate of approximately 36%.

(f) To reflect pro forma net income per basic and diluted share. Income
available to common stockholders and common stock equivalents are derived
as follows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999 SIX MONTHS ENDED JUNE 30, 2000
--------------------------------------- ---------------------------------------
INCOME SHARES PER SHARE INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT (NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- --------- ----------- ------------- ---------
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
Net income.............. $8,208 $16,088
Less preferred stock
dividends and
accretion of issuance
costs................. (836) 4,233
------ -------
Basic EPS:
Income available to
common stockholders... 7,372 14,246,727 $0.52 11,855 8,747,000 $1.36
===== =====
Effect of Dilutive
Securities:
Convertible preferred
stock................. 836 9,251,282 4,233 9,329,839
------ ----------- ------- -----------
Diluted EPS:
Income available to
common stockholders
plus assumed
conversions........... $8,208 23,498,009 $0.35 $16,088 18,076,839 $0.89
====== =========== ===== ======= =========== =====
</TABLE>

Exploration expense has not been included in the pro forma statements for
East Bay and South Timbalier 26 as there were no actual exploratory projects
during 1999 and 2000.

In November 1999, in connection with our private placement of preferred
stock with Evercore, our management stockholders tendered 3,304,830 shares of
common stock to escrow. Approximately 77% of these shares will be released from
escrow upon completion of this offering. In the period that these shares are
released from escrow, we will record compensation expense equal to the fair
value of the shares at that time. Assuming an offering price of $18.00,
compensation expense is estimated to be $45.5 million. This amount is not
reflected in our pro forma statements or in our historical financial statements.

26
<PAGE> 31

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion and analysis should be read in conjunction with
our selected historical financial data and unaudited pro forma financial
information and our accompanying financial statements and the notes to those
financial statements included elsewhere in this prospectus. The following
discussion includes forward-looking statements that reflect our plans, estimates
and beliefs. Our actual results could differ materially from those discussed in
these forward-looking statements. Factors that could cause or contribute to such
differences include, but are not limited to, those discussed below and elsewhere
in this prospectus, particularly in "Risk Factors."

OVERVIEW

We are an independent oil and natural gas exploration and production
company concentrated in the shallow to moderate depth waters of the central
region of the Gulf of Mexico Shelf. We were incorporated in January 1998 by
Richard A. Bachmann, our chairman, president and chief executive officer. Mr.
Bachmann provided our initial capital.

In April 1998, we entered into a $20.0 million financing arrangement, later
increased to $25.0 million, with Energy Income Fund, in the form of a private
debt and equity placement. We used the proceeds to purchase interests in South
Timbalier 26 and for drilling and workover expenditures for the drill-to-earn
programs covering the Bay Marchand field and the Main Pass 122/133 field with
Chevron. Please read "Business and Properties" for a further description of
these drill-to-earn programs. In November 1999, we raised an additional $60.0
million in a private equity offering with Evercore. We used a portion of the
proceeds to repay $15.0 million of outstanding Energy Income Fund debt and to
repay $15.3 million of outstanding debt under a bank line that we had with Bank
One.

We have grown our company through a combination of drill-to-earn programs
and strategic acquisitions. Our drill-to-earn programs allow us to identify and
pursue additional drilling opportunities on properties previously developed by
our drill-to-earn partners. In March 2000, we acquired Unocal's 80% interest in
South Timbalier 26. In April 2000, we sold to Vastar 50% of our working interest
in South Timbalier 26. The net cash paid for our increased interest in the field
was $8.5 million. Additionally, on March 31, 2000, we closed the purchase of an
average 98.5% working interest in the East Bay field from Ocean Energy for $72.6
million.

The East Bay and South Timbalier 26 acquisitions significantly altered our
operations and future results and reduced our exposure to any particular well.
We increased our active well count from 12.8 net producing wells to 386.6 net
producing wells after these acquisitions. As of June 30, 2000, we had
approximately 106 full-time employees, including 22 geoscientists and engineers
and 64 field personnel, representing an increase of 73 employees from December
31, 1999.

We have also experienced substantial revenue and production growth as a
result of the East Bay and South Timbalier 26 acquisitions. On a pro forma basis
for the six months ended June 30, 2000, revenues would have been of $56.3
million as compared with our actual total revenues of $30.0 million. On a pro
forma basis for the six months ended June 30, 2000, production would have been
2,250,000 Boe as compared with our actual 1,212,000 Boe.

Although the East Bay and South Timbalier 26 acquisitions had an effective
date of January 1, 2000, we reduced our purchase price on March 31, 2000 by the
net cash flows collected by the sellers (Unocal and Ocean Energy) during the
period from January 1, 2000 through March 31, 2000. Accordingly, we did not
include the results of operations from these acquisitions in our March 31, 2000
operational or financial results, but only in the pro forma computations.

The financings related to the East Bay and South Timbalier 26 acquisitions
substantially increased our debt levels. As of March 31, 2000, we had $118.2
million in total debt outstanding. We incurred
27
<PAGE> 32

$108.0 million of this debt as a result of the East Bay and South Timbalier 26
acquisitions. On April 20, 2000, we sold 50% of our interest in the South
Timbalier 26 field to Vastar and used the proceeds to reduce outstanding debt.
As of June 30, 2000, our total debt outstanding was $75.0 million.

For the foregoing reasons, the East Bay and South Timbalier 26 acquisitions
will affect the comparability of our historical results of operations with
results of operations in future periods.

In September 2000, we closed the acquisition of Texaco's 14.5% working
interest in South Timbalier 22, 23 and 27. We acquired this interest effective
January 1, 2000 for a cash price of approximately $2.2 million, net of closing
adjustments. Our reserves and production associated with this interest are not
included in the reserve and production information in this prospectus.

Our revenue, profitability and future growth rate depend substantially on
factors beyond our control, such as economic, political and regulatory
developments and competition from other sources of energy. Oil and natural gas
prices historically have been volatile and may fluctuate widely in the future.
Sustained periods of low prices for oil and natural gas could materially and
adversely affect our financial position, our results of operations, the
quantities of oil and natural gas reserves that we can economically produce and
our access to capital.

We use the successful efforts method of accounting for our investment in
oil and natural gas properties. Under this method, we capitalize lease
acquisition costs, costs to drill and complete exploration wells in which proven
reserves are discovered and costs to drill and complete development wells.
Seismic, geological and geophysical, and delay rental expenditures are expensed
as incurred. Please read note 2 to our financial statements.

We conduct many of our exploration activities jointly with others and,
accordingly, recorded amounts for our oil and natural gas properties reflect
only our proportionate interest in such activities.

RESULTS OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2000 COMPARED TO THE SIX MONTHS ENDED JUNE 30,
1999.

General. We increased our net production to 6,658 Boe per day in the first
six months of 2000, a 400% increase from 1,332 Boe per day in the first six
months of 1999.

Oil and Gas Revenues. Our oil and natural gas revenues increased to $30.0
million during the first six months of 2000 from $3.2 million in the first six
months of 1999. Oil revenues increased to $24.8 million during the first six
months of 2000 from $2.6 million, as a result of sharply increased average oil
prices ($13.0 million) and increased volumes ($10.6 million) associated with 23
successful well operations which commenced production after the first six months
of 1999. The increase in oil prices was offset by $1.8 million in losses on oil
hedging in the first six months of 2000. We did not have any hedging contracts
in place in 1999. Natural gas revenues increased to $5.2 million during the
first six months of 2000 from $0.6 million, as a result of increased average
natural gas prices ($2.5 million) and increased volumes associated with two
successful well operations which commenced production after the first six months
of 1999.

Lease Operating Expense (including production taxes). Lease operating
expense increased to $8.0 million in the first six months of 2000 from $.6
million in the first six months of 1999. The increase was primarily attributable
to additional production from 25 successful well operations which commenced
production after the first six months of 1999.

General and Administrative Expense. General and administrative expenses
increased to $5.2 million in the first six months of 2000 from $1.1 million in
the first six months of 1999. The increase was primarily due to increased
consultant fees ($1.1 million), the hiring of additional personnel ($2.3
million), increased insurance costs ($0.4 million) and other costs associated
with our acquisition of the East Bay field and the additional interest in the
South Timbalier 26 field on March 31, 2000. The 2000 expense also includes $0.8
million in compensation expense related to restricted stock and stock options.

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Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization increased to $8.3 million in the first six months of 2000 from $1.9
million in the first six months of 1999, primarily due to increased production
volumes during the six months.

Interest. Net interest expense increased to $2.7 million in the first six
months of 2000 from $1.2 million in the first six months of 1999. The increase
was a result of an increase in long-term debt outstanding related to our
acquisitions discussed above.

Gain on Sale of Oil and Gas Assets. On April 20, 2000, we sold a 50%
working interest in the South Timbalier 26 field, resulting in a gain of
approximately $7.8 million. There were no sales for the same period in 1999.

Net Income. As a result of the conditions noted above, we recognized net
income of $8.5 million in the first six months of 2000 compared to a net loss of
$.7 million in the first six months of 1999.

YEAR ENDED DECEMBER 31, 1999 COMPARED TO THE PERIOD ENDED DECEMBER 31,
1998.

General. Our operations did not commence until June 1998, which has
affected the comparability of the financial results with subsequent periods. We
increased our net production to 1,431 Boe per day during 1999, a 90% increase
from 753 Boe per day during 1998.

Oil and Gas Revenues. Our oil and gas revenues increased to $8.5 million
during 1999 from $1.8 million during 1998. Oil revenues increased to $6.7
million during 1999 from $1.3 million, as a result of sharply increased average
oil prices ($1.7 million) and increased volumes ($3.7 million) associated with
14 successful well operations which commenced production during 1999. Natural
gas revenues increased to $1.8 million during 1999 from $.5 million, primarily
as a result of increased natural gas volumes ($1.3 million) and decreased
average natural gas prices ($.1 million). The vast majority of natural gas
production during 1999 was derived from associated natural gas from oil
production.

Lease Operating Expense (including production taxes). Lease operating
expense increased to $1.6 million in 1999 from $.4 million in 1998. The increase
was primarily attributable to the additional production from 14 successful well
operations which commenced production during 1999.

Exploration Expenditures and Dry Hole Costs. We use the successful efforts
method to account for oil and gas exploration, evaluation and development
expenditures. Under this method $1.5 million of dry hole costs were incurred and
$.1 million of seismic, geological and geophysical expenditures were expensed in
1999. No such charges occurred in 1998.

General and Administrative Expense. General and administrative expenses
increased to $2.6 million in 1999 from $.6 million in 1998, primarily due to
employment-related costs associated with an increase in personnel in late 1998
and 1999.

Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization increased to $4.5 million in 1999 from $1.3 million in 1998,
primarily due to a substantial increase in production during 1999.

Interest. Net interest expense increased to $2.6 million in 1999 from $.8
million in 1998, as a result of additional borrowings under our credit agreement
during 1999.

Net Loss. As a result of the conditions noted above, we recognized a net
loss of $2.3 million in 1999 compared to a net loss of $.7 million in 1998.

LIQUIDITY AND CAPITAL RESOURCES

We intend to use cash flows from operations primarily to fund our future
development, exploration and acquisition activities. Our recent acquisition of
the East Bay field and additional interests in South Timbalier 26 field
significantly impacted our cash flows from operations. Our future cash flow from
operations will depend on our ability to maintain and increase production
through our development and exploration drilling program, as well as the prices
of oil and natural gas.
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In February 1999, we borrowed an additional $5.0 million under our
financing agreement with Energy Income Fund, a stockholder, raising the total
outstanding under the agreement to $25.0 million. The terms of the remaining
$10.0 million of subordinated debt due to Energy Income Fund require repayment
by July 1, 2001. We plan to repay in full outstanding amounts under this
agreement with a portion of the proceeds of this offering. In June 1999, we
entered into a reducing revolving line of credit of $50.0 million with Bank One,
which had a borrowing base of $20.0 million. In November 1999, we completed a
private placement with Evercore for shares of our preferred stock providing net
proceeds of $55.6 million. We used a portion of the proceeds from the private
placement to reduce our outstanding debt to Energy Income Fund by $15.0 million
and to Bank One by $15.3 million.

In March 2000, we entered into a new revolving line of credit with Bank
One. The new agreement provided for a $90.0 million Tranche A reducing revolving
line of credit that terminates March 30, 2003 and a $25.0 million Tranche B
reducing bridge financing that terminates March 30, 2001. Tranche A bears
interest at LIBOR plus 3.0% and Tranche B bears interest at LIBOR plus 5.5%.
Beginning June 1, 2000 through October 1, 2000, Tranche A is reduced monthly by
$1.4 million and Tranche B is reduced monthly by $0.4 million. We borrowed
$108.0 million under the credit facility to finance the East Bay and South
Timbalier 26 acquisitions. In April 2000, the proceeds from the sale to Vastar
were used to reduce the outstanding balance of the credit facility to $71.8
million. Subsequent to the repayment of the Tranche B loan, Tranche A will bear
interest at LIBOR plus 1.25% to 2.25%, based on the level of utilization of the
line of credit.

At June 30, 2000, we had $65.0 million of total outstanding debt under our
bank facility and $7.2 million of credit capacity available under this facility.
The Bank One credit facility is secured by substantially all of our assets. We
intend to repay substantially all amounts outstanding under this facility with
the proceeds of this offering and renegotiate our credit facility.

Net cash of $84.8 million used in investing activities in the first six
months of 2000 included net oil and gas property capital expenditures of $4.1
million and the East Bay and South Timbalier 26 acquisitions (prior to the sale
to Vastar) of $117.4 million. During the first six months of 2000, we completed
13 drill projects and nine recompletion/workover projects, 19 of which were
successful. In 1999, we completed six drill projects and four
recompletion/workover projects, eight of which were successful. Cash and cash
equivalents at June 30, 2000 were $6.7 million.

Our 2000 capital expenditure budget is focused on exploitation activities
on prospects with multiple reservoirs, which we expect to increase our
probability of success and to lead to accelerated payback of our investment.
These exploitation activities also provide exploratory potential in deeper
geologic formations. We have capital expenditure plans for the last six months
of 2000 totaling approximately $41.5 million related to 91 projects.
Additionally, capital expenditures for 2001 and 2002 are estimated to be
approximately $134.0 million. Actual levels of capital expenditures may vary
significantly due to many factors, including drilling results, oil and natural
gas prices, industry conditions, participation by other working interest owners
and the prices of drilling rigs and other oilfield goods and services.

In November 1999, in connection with our private placement of preferred
stock with Evercore, our management stockholders tendered 3,304,830 shares of
common stock to escrow. Approximately 77% of these shares will be released from
escrow upon completion of this offering. In the period that the shares are
released, we will record compensation expense equal to the fair value of the
shares at that time. Assuming an offering price of $18.00, compensation expense
is estimated to be $45.5 million. This amount is not reflected in our historical
or pro forma financial statements.

We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active capital expenditure
program. While we believe that the proceeds of this offering, working capital,
cash flows from operations and borrowings under our credit facility will be
sufficient to meet our capital requirements through the end of 2001, additional
financing may be required in the future to fund our growth and capital
expenditures.

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HEDGING ACTIVITIES

In April 2000, we entered into hedging transactions for our oil production
to reduce our exposure to fluctuations in the price of oil. Our hedging
transactions have to date consisted of financially settled crude oil forward
sales contracts with major financial institutions as required by our bank
facility entered into in connection with the acquisitions of the East Bay field
and additional interests in the South Timbalier 26 field. To qualify as a hedge,
these contracts must correlate to anticipated future production such that our
exposure to the effects of commodity price changes is reduced. We financially
settle our crude oil forward sales contracts based on the average of the
reported settlement prices for West Texas Intermediate crude on the NYMEX for
each month. With our hedges, the counterparty is required to make a payment to
us if the settlement price for any settlement period is below the hedged price
for the transaction, and we are required to make a payment to the counterparty
if the settlement price for any settlement period is above the hedged price for
the transaction. The gains and losses related to these hedging transactions are
recognized as adjustments to the revenue recorded for the related production. We
use the accrual method of accounting for derivative commodity instruments. At
inception, any contract premiums paid are recorded as prepaid expenses and, upon
settlement of the hedged production month, are included with the gains and
losses on the contracts in the oil and natural gas revenues.

We may in the future enter into these and other types of hedging
arrangements to reduce our exposure to fluctuations in the market prices of oil
and natural gas. Hedging transactions expose us to risk of financial loss in
some circumstances, including if production is less than expected, the other
party to the contract defaults on its obligations, or there is a change in the
expected differential between the underlying price in the hedging agreement and
actual prices received. Hedging transactions may limit the benefit we would have
otherwise received from increases in the prices for oil and natural gas.
Furthermore, if we do not engage in hedging transactions, we may be more
adversely affected by declines in oil and natural gas prices than our
competitors who engage in hedging transactions.

Additionally, hedging transactions may expose us to cash margin
requirements. We use primarily over-the-counter hedge instruments with major
financial institutions where margin requirements have been negotiated.
Typically, we have negotiated volumetrically based credit limits where no cash
margin is required.

As of June 30, 2000, we had contracts maturing monthly through May 2001
related to the sale of 2,153,000 barrels of oil at an average price of $23.86
per barrel. Had these contracts been terminated at June 30, 2000, we estimate
the loss would have been $9.7 million. As of June 30, 2000, the hedged volume
approximated 54% of our estimated oil production from proved reserves through
June 2001.

NEW ACCOUNTING POLICIES

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities." Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains or losses) depends on
the intended use of the derivative and resulting designation. If certain
conditions are met, a derivative may be specifically designated as a "fair value
hedge," "cash flow hedge," or a hedge of the foreign currency exposure of a net
investment in a foreign operation. Statement 133 amends and supersedes a number
of existing Statements of Financial Accounting Standards, and nullifies or
modifies the consensus reached in a number of issues addressed by the Emerging
Issues Task Force. Statement 133, as amended, is effective for all fiscal
quarters of fiscal years beginning after June 15, 2000. We are assessing the
impact of adoption of Statement 133 and, at the present time, have not
quantified the effect of adoption or the continuing impact of such adoption.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

We are exposed to changes in interest rates. Changes in interest rates
affect the interest earned on our cash and cash equivalents and the interest
rate paid on borrowings under the credit agreements. Under our current policies,
we do not use interest rate derivative instruments to manage exposure to
interest rate changes. At June 30, 2000, $65.0 million of our long-term debt had
variable interest rates. Based on the debt outstanding at June 30, 2000, a 10%
increase in variable rates would increase our interest expense by $0.4 million
on an annual basis.

COMMODITY PRICE RISK

Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and natural gas. Prices also affect the amount of cash
flow available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under the new credit agreement with
Bank One is subject to periodic redetermination based in part on changing
expectations of future prices. Lower prices may also reduce the amount of oil
and natural gas that we can economically produce. We currently sell all of our
oil and natural gas production under price sensitive or market price contracts.

In April 2000, pursuant to Bank One debt requirements, we entered into
derivative commodity instruments to manage commodity price risks associated with
future oil production. Our commodity price hedging program uses financially
settled crude oil forward sales contracts and we do not use them for speculative
purposes. As of June 30, 2000, we had contracts maturing monthly through May
2001 related to the sale of 2,153,000 barrels of oil at an average price of
$23.86 per barrel. As of June 30, 2000, the hedged volume approximated 54% of
our estimated oil production from proved reserves through June 2001. Had these
contracts been terminated at June 30, 2000, we estimate the loss would have been
$9.7 million.

We use a sensitivity analysis technique to evaluate the hypothetical effect
that changes in the market value of crude oil may have on fair value of our
derivative instruments. At June 30, 2000, the potential change in the fair value
of commodity derivative instruments assuming a 10% adverse movement in the
underlying commodity price is a $6.1 million increase in the deferred cost.

For purposes of calculating the hypothetical change in fair value, the
relevant variables are the type of commodity (crude oil or natural gas), the
commodities futures prices and volatility of commodity prices. The hypothetical
fair value is calculated by multiplying the difference between the hypothetical
price and the contractual price by the contractual volumes.

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BUSINESS AND PROPERTIES

OVERVIEW

We are an independent oil and natural gas exploration and production
company concentrated in the shallow to moderate depth waters of the central
region of the Gulf of Mexico Shelf. This region has produced over 27 billion
barrels of oil equivalent and contains over 500 oil and natural gas fields, 25
of which have individually produced over 250 million barrels of oil equivalent.
Most of our properties are located in the Terrebonne Trough area of this region.
We have focused on this area because it provides us with favorable economic and
geologic conditions, including multiple reservoir formations, regional economies
of scale, extensive infrastructure and comprehensive geologic databases. We
believe that the large, established fields in this region offer a balanced and
ample inventory of existing and prospective exploitation and development
opportunities, as well as the long-term potential for reserve additions and
production increases from deeper geologic formations.

OUR STRATEGY

We were founded to address a challenge that major integrated and large
independent energy companies face with respect to maximizing the value of their
Gulf of Mexico Shelf assets. These companies are currently redirecting human and
financial resources away from this area to the deepwater Gulf of Mexico and
other areas around the world that have greater growth potential relative to
their existing asset base. Two alternatives these large energy companies may
pursue in order to maximize the value of their Shelf assets are to enter into
drill-to-earn programs with a company like ours or to sell their properties.

Our drill-to-earn programs offer numerous benefits for us and our partners.
The property owner participates with us in any increases in production and cash
flow. Since we typically use our staff and capital in these redevelopment
programs, the property owner also benefits from new reserve additions at no
incremental cost. Furthermore, by extending the life of the field, the property
owner is able to postpone taxable gains and abandonment liabilities. From our
standpoint, these established fields have a lower redevelopment risk profile and
the infrastructure already in place accelerates our cost recovery and lowers our
cost of reserve additions. In addition, we gain exposure to drilling
opportunities with greater upside potential at reduced costs.

- Maintaining our Gulf of Mexico focus. Since our inception, we have
focused on the large, established fields in the central Gulf of Mexico
Shelf area. We intend to continue this focus. Our industry contacts,
track record and established credibility with significant Shelf operators
position us to grow reserves and production by entering into multi-well,
multi-year drill-to-earn programs with operators with significant
positions in the Gulf of Mexico Shelf. We believe that we will
successfully identify and develop these opportunities by leveraging our
extensive geophysical, technical and operational expertise. We believe
that this region's extensive infrastructure and favorable geologic
conditions with multiple known oil and natural gas producing reservoirs
will allow us to achieve attractive returns on our investments.

In the near term, we intend to pursue low-risk opportunities for
exploitation, development and exploration drilling and workover
activities. In the long term, we believe that the fields offer high-
potential exploration opportunities in the deeper reservoirs because
limited drilling has occurred below the depth of 14,000 feet.

- Capitalizing on our geoscience expertise. Our geologists and
geophysicists internally generate and evaluate prospects in their current
area of focus and in connection with our new business initiatives. To
identify prospects, we use traditional geologic evaluation techniques
which are enhanced by our

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licensed D3D seismic data processing technology. Our drill-to-earn
programs give our technical teams access to our partners' technical
databases to identify and implement successful and profitable
development, exploitation and exploration activities.

Our strategy to consolidate strategic, contiguous acreage positions in
our core area provides us with the opportunity to integrate numerous
databases for the first time. We believe the integration of these
databases lends additional perspective on potential project opportunities
near lease boundaries as well as better interpretation of the broad
geologic characteristics of the project area. For instance, we are the
first operator to control all of the existing geophysical data in the
Greater Bay Marchand area, which we believe provides us with considerable
advantages in evaluating our prospect inventory and new business
initiatives in this area.

- Continuing to operate our properties. We seek to retain operatorship
following an acquisition or in connection with drill-to-earn programs.
Operatorship provides us with the opportunity to exercise greater control
over the cost, timing and nature of our development and exploitation
activities as well as to influence the timing and amount of plugging and
abandonment liabilities. As of June 30, 2000, we operated approximately
88% of our production.

Since we began operating the South Timbalier 26 field in June 1998, we
have reduced per Boe operating costs by 22% to an average of $5.15 per
Boe. At East Bay, we have already reduced the per barrel operating costs
by 10% to $5.91 per Boe since assuming operations on April 1, 2000. In
addition to providing improvements in profitability, our ability to lower
operating costs serves to extend field life and increase the potential
ultimate recovery of reserves in our core area. For every $0.50 per
barrel of oil equivalent reduction in operating costs, the pre-tax
present value of our reserves in East Bay increases by $13.6 million and
the ultimate recoverable reserves increase by 359 Mboe, based upon prices
in effect as of January 1, 2000. The identification, evaluation and
implementation of cost reductions and efficiency initiatives remain quite
active at all of our fields.

- Expanding our asset base through additional drill-to-earn programs and
strategic acquisitions. We believe we have an inventory of future
exploitation, development and exploration projects on our existing
properties that should allow us to increase our reserves and production
for at least the next three years. To enhance our inventory, we continue
to conduct detailed analyses of properties and acreage in our core area.
We combine our extensive knowledge of regional geology with industry
databases and other available data to identify new drill-to-earn and
acquisition opportunities. We then determine if the application of our
in-house technology and drilling and development expertise can yield
meaningful improvement to a project's reserve and production base. Our
objective is to negotiate a joint re-development alliance, a significant
drill-to-earn arrangement or outright purchase of the property with the
owners/operators of the property on terms consistent with our return
targets. We target both oil and natural gas properties that have high
cumulative production with low levels of current production, significant
identified proven reserves with potential for large reserve additions,
existing infrastructure and multiple productive reservoir targets.

- Maximizing profitability through outsourcing non-geoscience
activities. We seek to enhance our operating capability and achieve
operating cost savings through strategic alliances with oilfield service
companies. Currently, we have arrangements with Schlumberger, Brown and
Root, Production Management Companies and Cardinal Services. In addition
to closely controlling our operating costs, we reduce our administrative
overhead costs by outsourcing the majority of our accounting and
administrative functions.

OUR PRINCIPAL OIL AND NATURAL GAS PROPERTIES

EAST BAY FIELD

On March 31, 2000, we acquired the East Bay field and related production,
compression and storage facilities from Ocean Energy for $72.6 million, net of
the purchase price adjustment. The acquisition was effective January 1, 2000.
The purchase price reflects a reduction of $13.4 million for estimated cash flow

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from the period January 1 through March 31, 2000. This property met all of our
investment criteria and also provided us with a significant source of stable
production from a large number of wells.

As of January 1, 2000, our share of East Bay's proved reserves totaled
27,405 Mboe (83% oil). Our net daily production averaged 8,150 Boe in June 2000.

East Bay is located 89 miles southeast of New Orleans near the mouth of the
Mississippi River and contains producing wells onshore to water depths of
approximately 85 feet. The field encompasses nearly 48 square miles and is
comprised of three oil and natural gas fields, South Pass 24, 27 and 39. We are
the operator of these fields and own an average 98.5% working interest. Our net
revenue interest ranges from 82% to 86%. Our lease area covers 31,596 gross
acres (30,370 net acres), of which 4,330 gross and net acres are under federal
jurisdiction while 27,266 gross acres (26,040 net acres) are under the
jurisdiction of the State of Louisiana.

Production facilities related to the East Bay properties are located on the
east bank of the Southwest Pass of the Mississippi River. The major onshore
facilities consist of oil processing facilities with capacity for 30,000 Bbls
per day, an oil storage tank battery, a produced water treatment facility,
natural gas compression and dehydration facilities with a capacity of 200 Mmcf
per day, living quarters, electric power generators, instrument air systems,
sewage disposal, a boat maintenance shop and a loading dock. These facilities
provide a centralized operations hub with additional capacity to support
expanded production operations from this field or future acquisitions or joint
arrangements in the area.

East Bay, which Shell discovered in 1949, currently includes 409 active
wells, 26 major platforms which are still active and an additional 272 active
well production structures. East Bay has produced over 671 Mmbls and 1,250 Bcf
of natural gas, or 880 Mmboe, since discovery from over 107 geologic formations.

Shell developed East Bay between 1949 and 1993 using conventional 2-D
seismic and subsurface geological techniques. Production has been established
from numerous Pliocene and Upper Miocene age geologic formations from depths of
1,000 to 14,000 feet, with very limited drilling below 14,000 feet. Shell
acquired a proprietary 3-D seismic survey over the southern half of the field
(South Pass 27 field) in 1993, shortly before the field was sold to Flores &
Rucks, Inc. (now Ocean Energy). Ocean Energy acquired and processed a second
proprietary 3-D seismic survey over the northern half of the field (South Pass
24 field) in 1996 and 1997. During this same time period, Western Geophysical
acquired additional 3-D data in an area south of the field. Ocean Energy
conducted drilling operations between 1994 and 1998, primarily on the southern
South Pass 27 area, while they acquired and processed their new 3-D survey on
South Pass 24 to the north. No new drilling was conducted after 1998.

We are currently reprocessing the merged Western Geophysical and Ocean
Energy 3-D surveys by applying new seismic velocity data and by using our
licensed D3D seismic data technology. We believe that the resultant 3-D data set
will allow improved structural and stratigraphic interpretation for upcoming
drilling activity. We expect this effort will add additional low-risk
multiple-pay drilling opportunities to our existing inventory, many possessing
deeper exploratory objectives which can be tested at relatively low incremental
capital cost, although we cannot assure you that any new opportunities will in
fact be generated. We believe our geological, geophysical and production
engineering staff will generate numerous new opportunities in the field as they
assimilate and correlate the data we have amassed regarding the field.

To assist us in East Bay field operations, we formed an alliance with Brown
and Root Energy Services. Immediately upon assuming operatorship of the field,
we and our alliance partner initiated a comprehensive evaluation of the
production facilities, gas compression, water disposal, transportation,
chemicals, materials and rentals. We expect this study to generate improvements
in our production efficiency and reductions in our operating costs. A second
alliance was formed with Cardinal Services to redesign gas lift in wells and
increase production. Since assuming operations on April 1, 2000, we have already
reduced the per barrel operating costs by 10% to $5.91 per Boe.

Our management, technical and financial staff have many years of experience
working in the Louisiana tax and regulatory environment. At East Bay, we have
certified 626 qualifying wells with the

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Louisiana Office of Conservation as eligible for an exemption from state
severance taxes for a period of up to five years. Current Louisiana state
severance tax rates are 12.5% of value on oil and 9.7 cents per Mcf of natural
gas, but are subject to change by the state. We will attempt to use many of
these certified wells to deepen, sidetrack or workover in our ongoing
exploitation and development program and thereby secure a five-year state
severance tax exemption on future production from those wells. In addition, a
state severance tax exemption also exists for new horizontal wells drilled. We
plan to utilize this exemption, which lasts for a period of up to two years or
until payout occurs (whichever is earlier), wherever horizontal drilling is
planned. Oil production at East Bay is enhanced with artificial lift known as
gas lift and we receive a severance tax reduction on gas sold from these wells.
We believe the combination of these severance tax exemptions will increase the
rate of return on our reactivation program at East Bay.

THE GREATER BAY MARCHAND AREA

We have completed four separate transactions which together cover most of
the large Bay Marchand field. The Greater Bay Marchand area is located in state
and federal waters off the coast of Louisiana. This area, encompassing nearly
100 square miles, is a massive salt dome complex productive from approximately
130 Pliocene and Upper Miocene age geologic formations from depths of 1,500 to
16,500 feet. The first successful well was drilled in 1949 and since then the
area has recorded cumulative production of 894 Mmbls and 1,049 Bcf, or 1,069
Mmboe. Throughout the Greater Bay Marchand area, we are targeting
multiple-objective development drilling opportunities with, wherever possible,
untested or deeper potential reservoirs.

The area was developed separately by Chevron to the north and Shell to the
south using conventional 2-D seismic and subsurface geological techniques.
Proprietary 3-D seismic surveys acquired by Chevron in 1988 and Shell in 1989
covered their respective portions of the field, and were two of the earliest
attempts at 3-D field redevelopment in the shallow offshore Gulf of Mexico Shelf
area.

In mid-1998, we purchased Shell's portion of the field (South Timbalier 26)
and then negotiated drill-to-earn agreements on Chevron's portion of the field.
With the combination of these transactions, we became the first company to have
full access to all data from both major oil companies over the entire Bay
Marchand area. In addition to the Chevron and Shell 3-D seismic surveys, we have
also acquired a portion of a 1997 Western Geophysical 3-D survey that overlaps
and ties the two previous survey areas together. This third 3-D seismic survey
has been reprocessed and interpreted using our licensed D3D seismic data
technology, which has contributed to our drilling success. We believe we are the
first company able to view the Greater Bay Marchand area structure in its
entirety due to our combination of data from Chevron, Shell and Western. We
believe that this ability to analyze this field in its entirety provides
synergies in geology, geophysics, reservoir engineering and operations.

South Timbalier 26. During the first half of 1998, we negotiated the
purchase of a 100% working interest in the South Timbalier 26 field from Shell.
We brought in Unocal as our partner in the transaction and, in June 1998, we
completed the purchase. We acquired a 20% working interest in and operatorship
of the field and Unocal acquired the remaining 80% working interest. At the
effective time of purchase, our net share of proved reserves totaled 2.0 Mmbls
and 5.3 Bcf, or 2.9 Mmboe. Our purchase price was $9.0 million.

The field is located 72 miles south of New Orleans in federal water depths
of 60 feet or less and comprises the extreme southern flank of the Greater Bay
Marchand field area. There are five platform structures in use in the field, one
for crew quarters and four for production with a total of 19 productive wells.
The block covers 7.8 square miles and productive reservoirs range from 10,000 to
13,500 feet.

Shell acquired the block, drilled its first successful well in 1965 and
developed the field using conventional 2-D seismic and subsurface geological
techniques. In 1989, Shell acquired a proprietary 3-D seismic survey, and only
four wells were drilled after the survey was completed. In 1998, we worked
closely with Shell and proposed a drill-to-earn agreement. When Shell management
decided instead to sell the property, we were familiar with the field and were
in a position to negotiate exclusively an acquisition of the property.
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Concurrent with our purchase of the field, we acquired a portion of a new
Western Geophysical 3-D seismic survey covering South Timbalier 26 and portions
of contiguous blocks. We reprocessed this survey using our licensed D3D seismic
data technology. We combined this new data with existing seismic, subsurface and
reservoir engineering information to help reduce risk in our drilling program.

In March 2000, we acquired Unocal's 80% interest in South Timbalier 26. In
April 2000, we sold to Vastar 50% of our working interest in South Timbalier 26.
We continue to serve as operator and have created an area of mutual interest
with Vastar in an area surrounding South Timbalier 26. These transactions were
effective January 1, 2000. As of January 1, 2000, giving effect to our
acquisition of Unocal's interest and the sale of half of our interest to Vastar,
our share of proved reserves at South Timbalier 26 totaled 5,483 Mboe (67% oil).

Concurrent with the acquisition of South Timbalier 26, we formed a
strategic alliance with Production Management Companies. We conducted a detailed
evaluation of the field's production and other platform facilities and
implemented a series of improvements. Concurrently, we initiated a number of
lease operating cost reduction measures. The combination of reducing absolute
costs together with increasing production volumes enabled us to lower our
average lease operating costs per Boe by 22% to $5.15 from $6.63 prior to our
acquisition of the property.

During 1998 and 1999, we invested a total of $1.8 million at South
Timbalier 26 in the drilling of three wells, all of which were successful, and
the workover or recompletion of nine wells, eight of which were successful. The
combination of these activities increased our net proved reserves by 986 Mboe
and increased our net production from an average of 415 Boe per day at the time
the property was acquired to an average of 640 Boe per day in December 1999.

At South Timbalier 26 during the first six months of 2000, we have invested
a total of $5.4 million in the drilling or sidetracking of three wells, two of
which were successful, and the workover or recompletion of five wells, all of
which were successful. As a result of these activities and our larger interest
in the field, we increased our net average production to 1,670 Boe per day in
June 2000.

Bay Marchand Drill-to-Earn Agreements with Chevron. In August 1998, we
entered into a drill-to-earn agreement with Chevron covering their federal outer
continental shelf acreage in the Greater Bay Marchand field. This 30-square mile
area comprises the east flank and part of the south flank of the field. This
portion of the field is about 60 miles south of New Orleans in approximately 50
feet of water. It was developed by Chevron from 1949 to 1988 using conventional
2-D seismic and subsurface geological techniques, and after 1988, using a
proprietary 3-D seismic survey. Chevron owns 49 platforms and 37 productive
wells in this area of the field. Our South Timbalier 26 field is adjacent to the
southern border of this Chevron property.

We own a 30% gross working interest (24.75% net revenue interest) in the
drill-to-earn agreement, with the working interest in a particular operation
contingent upon the nature of the operation, its success and the price of oil at
the time the operation is commenced. To date, our well cost participation has
ranged from 22.5% to 60%; our working interest from 19.1% to 45%; and our net
revenue interest from 15.6% to 36.7% (before payout). We are the operator of the
drilling and completion of wells under our program and Chevron serves as
operator of production operations. Our agreement provides for the drilling of
additional wells on a continuing basis for a three-year term. Based on our
results to date, we have begun discussing an extension of the agreement with
Chevron.

In May 2000, we expanded our presence in Bay Marchand by executing a
separate drill-to-earn agreement with Chevron covering their Louisiana state
Shelf acreage. This approximately 50-square mile area comprises the north flank
and the shallow crest of the Greater Bay Marchand field. This portion of the
field is about 55 miles south of New Orleans in water depths up to approximately
50 feet and was developed by Chevron similarly to the federal outer continental
shelf acreage. Our successful performance on Chevron's adjacent federal outer
continental shelf portion of the field led to this subsequent agreement covering
the state lease portion. Chevron owns 51 platforms and 44 productive wells in
this area of the field.

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<PAGE> 42

We are the operator of the drilling and completion of wells covered under
this program and own an 80% gross working interest (66% net revenue interest) in
the drill-to-earn agreement. To date, our well cost participation has ranged
from 16.7% to 40%; our working interest from 12.5% to 34%; and our net revenue
interest from 10.3% to 28.1% (before payout). Chevron serves as operator of
production operations. Our agreement in the area provides for an initial
two-well drilling commitment, an option to propose an additional six-well
program and the possible extension of the agreement for an additional year of
drilling with our mutual written consent.

By virtue of our agreements with Chevron, we have access to Chevron's Bay
Marchand personnel and data, including 3-D seismic, well logs, test and
production information. By evaluating this data, we have identified numerous
opportunities for reestablishing production from inactive wells and enhancing
production from existing wells. We have from time to time participated in wells
proposed by Chevron at Bay Marchand outside of our existing drill-to-earn
program on favorable terms. A majority of the opportunities we are pursuing
under these agreements are low-risk recompletion operations and sidetracks of
existing wells.

From inception of our drill-to-earn program with Chevron at Bay Marchand
through December 1999, we invested a total of $9.4 million in drilling or
sidetracking a total of five wells, four of which were successful, as well as
the workover or recompletion of nine wells, five of which were successful. Our
Bay Marchand drilling and workover program added net reserves of 1,301 Mboe and
increased our net production at Bay Marchand to an average of 339 Boe per day in
December 1999.

As of January 1, 2000, our share of proved reserves at Bay Marchand totaled
1,411 Mboe (83% oil).

At Bay Marchand during the first six months of 2000, we invested a total of
$8.7 million in the drilling or sidetracking of ten wells, all of which were
successful, and the workover or recompletion of four wells, two of which were
successful. As a result of these activities, we increased our production to an
average of 785 Boe per day in June 2000. To date, we have generated $3.9 million
in revenues from these drill-to-earn programs and they currently account for 7%
of our daily production.

South Timbalier 22, 23 and 27. In October 1999, we acquired a 12.5% working
interest (10.4% net revenue interest) in South Timbalier 22, the south half of
South Timbalier 23 and the northeast quarter of South Timbalier 27 for $1.4
million. Our average net production from this property in December 1999 was 151
Boe per day. Our share of proved reserves as of January 1, 2000 totaled 383 Mboe
(67% oil).

We recently exercised a preemptive right to purchase an additional 14.5%
working interest from Texaco effective January 1, 2000 in a transaction that
closed in September 2000. Our purchase price for this interest totaled $2.2
million, net of closing adjustments reflecting net cash flow generated from
January 1, 2000, through the date of closing. The proved reserves associated
with this increased interest in the field, which totaled 473 Mboe as of January
1, 2000 (71% oil), have not been included in the NSAI reserve reports as of
January 1, 2000 or July 1, 2000.

This 13.6-square mile area is approximately 65 miles south of New Orleans
in approximately 50 feet of water. This property represents the south and
southwest flanks of the Greater Bay Marchand area. Chevron is the operator of
these properties and owns five platforms and 14 productive wells in this area.
We purchased these interests because they overlap the southern Chevron federal
outer continental shelf Bay Marchand acreage and adjoin both the Chevron and
South Timbalier 26 acreage to the west. Strategically, this enabled us to
increase our interest in existing and future wells on a portion of Chevron's
block. We own 3-D seismic surveys covering these properties.

MAIN PASS 122/133

In June 1998, we commenced our first drill-to-earn program with Chevron
covering Main Pass 122/133. It was a four-well drilling commitment. Under the
terms of the agreement, we retained 100% of Chevron's working interest in the
wells (100% in two wells and 69% in the other two wells). We are entitled to
recoup our investment plus a specified return through 75% of the production
stream. Chevron is responsible for lease operating costs out of their retained
25% production interest. Following
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<PAGE> 43

payout, which has not yet occurred, our interest will decrease to 1%. We have
completed our four well commitment with a total investment of $16.5 million with
cumulative revenues of $5.7 million at June 30, 2000. As of June 2000, Main Pass
122/133 accounted for approximately 4% of our daily production.

We undertook this limited drilling program at Main Pass to establish
ourselves as a successful operator in the Gulf of Mexico and qualify us before
the Minerals Management Service of the United States Department of the Interior
("MMS") and other regulatory agencies. We also believed it would provide us with
the operating history and track record to negotiate additional drill-to-earn
agreements and acquisitions.

All four wells under our agreement were successfully drilled during 1998
and encountered multiple reservoirs. We have completed this drill-to-earn
program and do not expect any further drilling activity in this field. Chevron
currently operates all of the wells. Our net production averaged 453 Boe per day
in December 1999.

Proved reserves associated with our interest in these wells totaled 792
Mboe as of January 1, 2000 (27% oil). Our net daily production from these wells
averaged 480 Boe in June 2000.

OUR OPERATIONAL RESULTS FROM INCEPTION THROUGH DECEMBER 31, 1999

From our inception through December 31, 1999, we invested $10.5 million for
proved reserve acquisitions of 3.3 Mmboe in the Greater Bay Marchand area, which
includes South Timbalier 22, 23, 26 and 27. In addition, we invested an
aggregate of $33.4 million in drilling, completion and workover activities and
$1.2 million in facilities improvements. We completed 11 successful wells or
sidetracks of existing wells, and 13 successful workovers and recompletions.
Those activities resulted in the addition of 3.3 Mmboe of new proved reserves.
Our total net production grew to an average of 1,583 Boe per day in December
1999 from inception.

OUR YEAR-TO-DATE INVESTMENT ACTIVITIES

From January 1 through June 30, 2000, we invested a total of $14.7 million
in drilling, completion and workover activities on our existing properties. We
completed 12 successful wells or sidetracks of existing wells, and seven
successful workovers and recompletions. We estimate that these investments
resulted in the addition of 1,236 Mboe of new proved reserves and the
reclassification of 2,077 Mboe to proved developed producing from the proved
developed non-producing and proved undeveloped reserve categories.

In addition, we completed the East Bay and South Timbalier 26 acquisitions
in March 2000. Net of the effect of our subsequent sale of 50% of our working
interest in South Timbalier 26 and estimated operating cash flow during the
first quarter from the interests acquired, we invested a total of $86.6 million
on these strategic purchases. We added net proved reserves related to these
acquisitions of 23.1 Mmbls and 30.3 Bcf, or 28.2 Mmboe, as of March 31, 2000.

We increased our total net production from 1,583 Boe per day in December
1999 to 11,200 Boe per day during the month of June 2000, reflecting the
combined results of our drilling and acquisition programs.

OUR FUTURE PLANNED INVESTMENT PROJECTS

We believe we have an inventory of future exploitation, development and
exploration projects on our existing properties that will allow us to increase
reserves and production for at least the next three years.

For the last six months of 2000, we have budgeted $41.5 million for
drilling and workovers and $2.5 million for compressor upgrades. We currently
have over 91 projects scheduled, including 72 workovers and recompletions and 19
new wells or sidetracks of existing wells.

At East Bay, our initial investment program is aimed at increasing
production and improving operating efficiency. For the last six months of 2000,
we have budgeted $20.4 million for a total of

39
<PAGE> 44

67 projects, which includes 40 workovers, 24 recompletions and three new
drilling opportunities. Over the next 24 months, we expect to invest $10.0
million to upgrade the field's compression facilities with the goal of
increasing natural gas sales capacity by 50.0 Mmcf per day while reducing fuel
consumption by 10% to 15%. We have budgeted $2.5 million for the first phase of
compression upgrades for the last six months of 2000.

Substantially all of this year's scheduled well work at East Bay is focused
on developing proved undeveloped reserves and bringing proved developed
non-producing reserves onstream. As a consequence, our finding and development
costs per barrel equivalent will be substantially higher at East Bay than
elsewhere in our operations where we are targeting new reserve additions as well
as development of proved undeveloped reserves.

At the Greater Bay Marchand area, which includes South Timbalier 22, 23, 26
and 27 and our drill-to-earn programs with Chevron, we have budgeted
approximately $21.1 million for the last six months of 2000 for a total of 24
projects, which includes eight workovers and recompletions and 16 new wells or
sidetracks of existing wells.

For 2001 and 2002, we estimate capital expenditures of approximately $134.0
million. We plan to invest approximately $39.1 million on 88 identified
workovers and recompletions, with 83 at East Bay and five at the Greater Bay
Marchand area. In addition, we estimate approximately $94.9 million in
expenditures for 74 new wells or sidetracks, with 22 at East Bay and 52 at the
Greater Bay Marchand area. Expected facility improvements include approximately
$7.5 million for the gas compression project at East Bay.

Although we expect to complete the projects discussed above, there can be
no assurance that these operations will be conducted or successful. Please read
"Risk Factors" for a discussion of some factors that may affect the timing of
drilling.

OIL AND NATURAL GAS RESERVES

The following table presents our estimated net proved oil and natural gas
reserves and the present value of our reserves at January 1, 2000, based on a
reserve report prepared by Netherland, Sewell. Appendix A to this prospectus
contains a letter prepared by Netherland, Sewell summarizing the reserve report.
The present values, discounted at 10% per annum, of estimated future net cash
flows before income taxes shown in the table are not intended to represent the
current market value of the estimated oil and natural gas reserves we own.

The present value of future net cash flows before income tax as of January
1, 2000 was determined by using the December 31, 1999 prices of $2.33 per Mmbtu
of natural gas and $25.60 per Bbl of oil, adjusted by lease for energy content,
transportation fees and regional price differentials.

<TABLE>
<CAPTION>
NET RESERVES FUTURE NET REVENUE
------------------------ ----------------------------
OIL GAS PRESENT WORTH
CATEGORY (BBLS) (MCF) TOTAL AT 10%
-------- ---------- ----------- ------------ -------------
<S> <C> <C> <C> <C>
Proved Developed:
Producing............................. 16,999,350 1,259,888 $109,261,400 $113,795,300
Non-Producing......................... 7,991,757 31,215,870 162,343,200 111,677,000
Proved Undeveloped...................... 3,049,084 12,127,491 54,811,400 33,053,100
---------- ---------- ------------ ------------
Total Proved.................. 28,040,191 44,603,249 $326,416,000 $258,525,400
========== ========== ============ ============
</TABLE>

Based on a reserve report prepared by Netherland, Sewell as of July 1,
2000, our net proved oil reserves totaled 27,782,254 Bbls and our net proved
natural gas reserves totaled 41,666,197 Mcf. The present value of future net
cash flows before income tax totaled $419.4 million and was determined using
June 30, 2000 prices of $4.48 per Mmbtu of natural gas and $32.50 per Bbl of
oil, adjusted by lease for energy content, transportation fees and regional
price differentials.

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<PAGE> 45

PRODUCTIVE WELLS

The following table sets forth the number of productive oil and natural gas
wells in which we owned an interest as of June 30, 2000:

<TABLE>
<CAPTION>
TOTAL
PRODUCTIVE
WELLS
-----------
GROSS NET
----- ---
<S> <C> <C>
Oil......................................................... 382 350
Natural gas................................................. 38 37
--- ---
Total............................................. 420 387
=== ===
</TABLE>

Productive wells consist of producing wells and wells capable of
production, including oil wells awaiting connection to production facilities and
natural gas wells awaiting pipeline connections to commence deliveries.

ACREAGE

The following table sets forth information as of June 30, 2000 relating to
acreage held by us. Developed acreage is assigned to producing wells. We have no
undeveloped acreage positions at this time.

<TABLE>
<CAPTION>
GROSS NET
ACREAGE ACREAGE
------- -------
<S> <C> <C>
Developed:
East Bay.................................................. 31,596 30,370
Greater Bay Marchand Area:
Bay Marchand........................................... 520 153
South Timbalier 26..................................... 5,000 2,500
South Timbalier 22, 23 and 27.......................... 8,750 1,094
Main Pass 122/133......................................... 312 163
------ ------
Total............................................. 46,178 34,280
====== ======
</TABLE>

WELL ACTIVITY

The following table shows our well activity for the six months ended June
30, 2000, the period ended December 31, 1998 and the year ended December 31,
1999. In the table, "gross" refers to the total wells in which we have a working
interest and "net" refers to gross wells multiplied by our working interest in
these wells.

<TABLE>
<CAPTION>
JANUARY 29, 1998
(INCEPTION) TO YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, 1998 DECEMBER 31, 1999 JUNE 30, 2000
------------------ ------------------ ----------------
GROSS NET GROSS NET GROSS NET
------ ---- ------ ---- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development Wells:
Productive.................... 6.0 4.0 4.0 0.9 12.0 4.9
Non-Productive................ - - - - - -
--- --- --- --- ---- ---
Total................. 6.0 4.0 4.0 0.9 12.0 4.9
Exploration Wells:
Productive.................... - - 1.0 0.3 - -
Non-Productive................ - - 1.0 0.3 1.0 0.3
--- --- --- --- ---- ---
Total................. - - 2.0 0.6 1.0 0.3
</TABLE>

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<PAGE> 46

PRODUCTION

The following table presents a summary of our average production data per
day:

<TABLE>
<CAPTION>
PRO FORMA
JANUARY 29, 1998 SIX MONTHS SIX MONTHS
(INCEPTION) TO YEAR ENDED PRO FORMA ENDED ENDED
DECEMBER 31, 1998(1) DECEMBER 31, 1999 1999 JUNE 30, 2000 JUNE 30, 2000
-------------------- ----------------- --------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Daily Production Data:
Oil (Bbls).................... 534 1,051 10,457 5,303 9,724
Natural gas (Mcf)............. 1,311 2,277 20,356 8,127 15,826
Oil equivalents (Boe)......... 753 1,431 13,850 6,658 12,362
Average Realized Sales Prices:
Oil (per Bbl)................. $13.21 $17.39 $ 16.79 $25.70 $ 26.61
Natural gas (per Mcf)......... 2.20 2.17 1.93 3.52 3.21
Oil equivalents (per Boe)..... 13.18 16.22 15.52 24.76 25.04
</TABLE>

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

(1) Daily production data is calculated based on 182 days of operations in 1998.

USE OF D3D TECHNOLOGY

To assist us in reducing the dry hole risk associated with our drilling
program, we are using a new patented 3-D seismic process. We hold a perpetual
license to use the Diagnostic Three-Dimensional Seismic Process (D3D), patented
by Louis E. Willhoit, Jr., our vice-president of geophysics, in our oil and
natural gas activities. D3D is a 3-D seismic acquisition, processing and
evaluation method designed to enhance high-resolution imaging of potential oil
and natural gas reservoirs. Using visualization software analogous to that used
by the medical industry for magnetic resonance imaging and CAT scans, the
process focuses on subsurface 3-D acoustic impedance volumes or objects such as
reservoirs within geologic strata as opposed to interfaces between geologic
strata. When used in combination with conventional 3-D seismic, wellbore and
production data, we believe D3D offers improved subsurface structural and
stratigraphic interpretation, and may, in some cases, help to act as a predictor
of hydrocarbons. We plan to continue using this new process at both the East Bay
field and the Greater Bay Marchand area.

MARKETING

We market substantially all of the oil and natural gas from properties we
operate and from properties others operate where our interest is significant. A
majority of oil production from the East Bay field is sold under a contract with
Equiva Trading Company expiring June 2003 and assumed under the East Bay field
purchase agreement with Ocean Energy. Our oil, condensate and natural gas
production is sold to a variety of purchasers, typically at market-sensitive
prices. Our purchasers of oil and condensate include Chevron, Shell, Williams
Energy Marketing & Trading Company and Williams-Gulfmark Energy Company.
Currently, most of our natural gas production is sold to Duke Energy Trading and
Marketing, L.L.C. We believe that the prices for liquids and natural gas are
comparable to market prices in the areas where we have production. We also have
natural gas processing agreements for our production at our Bay Marchand and
East Bay fields with Dynegy Midstream Services, L.P. and Enterprise Gas
Processing, L.L.C.

Due to the nature of the markets for oil and natural gas, we do not believe
that the loss of any one of these customers would have a material adverse effect
on our financial condition or results of operation.

TITLE TO PROPERTIES

Our properties are subject to customary royalty interests, liens under
indebtedness, liens incident to operating agreements, liens for current taxes
and other burdens, including other mineral encumbrances and restrictions. We do
not believe that any of these burdens materially interferes with the use of our
properties in the operation of our business.

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<PAGE> 47

We believe that we have satisfactory title to or rights in all of our
producing properties. As is customary in the oil and natural gas industry,
minimal investigation of title is made at the time of acquisition of undeveloped
properties. We investigate title and obtain title opinions from counsel only
before commencement of drilling operations. We believe that title issues
generally are not as likely to arise on offshore oil and natural gas properties
as on onshore properties.

COMPETITION

We operate in a highly competitive environment for acquiring oil and
natural gas properties, marketing oil and natural gas and securing trained
personnel. Many of our competitors possess and employ financial, technical and
personnel resources substantially greater than ours, which can be particularly
important in Gulf of Mexico activities. Those 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 our financial or personnel resources permit. Our ability to
acquire additional prospects and to discover reserves in the future will depend
on our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and natural gas
industry. We cannot assure you that we will be able to compete successfully in
the future in acquiring prospective reserves, developing reserves, marketing
hydrocarbons, attracting and retaining quality personnel and raising additional
capital.

REGULATION

REGULATION OF TRANSPORTATION AND SALE OF NATURAL GAS

The Federal Energy Regulatory Commission ("FERC"), pursuant to the Natural
Gas Act and the Natural Gas Policy Act, regulates interstate natural gas
pipeline transportation rates and service conditions, both of which affect the
marketing of natural gas we produce, as well as the revenues received for sales
of such natural gas. Since the latter part of 1985, the FERC has endeavored to
make natural gas transportation more accessible to natural gas buyers and
sellers on an open and non-discriminatory basis. The FERC has stated that open
access policies are necessary to improve the competitive structure of the
interstate natural gas pipeline industry and to create a regulatory framework
that will put natural gas sellers into more direct contractual relations with
natural gas buyers by, among other things, unbundling the sale of natural gas
from the sale of transportation and storage services. Beginning in 1992, FERC
issued Order No. 636 and a series of related orders to implement its open access
policies. As a result of the Order No. 636 program, the marketing and pricing of
natural gas has been significantly altered. The interstate pipelines'
traditional role as wholesalers of natural gas has been terminated and replaced
by a structure under which pipelines provide transportation and storage service
on an open basis to others who buy and sell natural gas. Although the FERC's
orders do not directly regulate natural gas producers, they are intended to
foster increased competition within all phases of the natural gas industry.

The courts have largely affirmed the significant features of Order No. 636
and the numerous related orders pertaining to individual pipelines. However,
FERC continues to review and modify its regulations regarding the transportation
of natural gas. For example, FERC recently issued Order Nos. 637 and 637-A
which, among other things, (i) lift the cost-based cap on pipeline
transportation rates in the capacity release market until September 30, 2002,
for releases of pipeline capacity of less than one year, (ii) require pipelines
to provide shippers with more opportunities to use capacity for which they pay
by increasing rights to capacity segmentation and equalizing nomination
procedures, (iii) permit pipelines to charge different maximum, cost-based rates
for peak and off-peak periods and for different contract terms, (iv) permit, but
do not mandate, auctions for pipeline capacity, (v) require pipelines to
implement imbalance management services and to permit third-parties to provide
such services in competition with the pipeline's own service, (vi) restrict the
ability of pipelines to impose penalties for imbalances, overruns and
non-compliance with operational flow orders, and (vii) implement a number of new
pipeline reporting requirements intended to increase transparency in the market.
In addition, FERC recently implemented new regulations governing the procedure
for obtaining authorization to construct new pipeline facilities and

43
<PAGE> 48

has issued a policy statement establishing a presumption in favor of requiring
owners of new pipeline facilities to charge rates based solely on the costs
associated with such new pipeline facilities.

The Outer Continental Shelf Lands Act ("OCSLA"), which FERC implements as
to transportation and pipeline issues, requires that all pipelines operating on
or across the outer continental shelf provide open-access, non-discriminatory
service. FERC recently issued Order No. 639, requiring that virtually all
non-proprietary pipeline transporters of natural gas on the outer continental
shelf report information on their affiliations, rates and conditions of service.
Among FERC's purposes in issuing such rules was the desire to increase
transparency in the market to provide producers and shippers on the outer
continental shelf with greater assurance of open-access services on pipelines
located on the outer continental shelf and non-discriminatory rates and
conditions of service on such pipelines.

We cannot accurately predict whether the FERC's actions will achieve the
goal of increasing competition in markets in which our natural gas is sold.
Additional proposals and proceedings that might affect the natural gas industry
are pending before FERC and the courts. The natural gas industry historically
has been very heavily regulated; therefore, there is no assurance that the less
stringent regulatory approach recently pursued by FERC will continue. However,
we do not believe that any action taken will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and
marketers.

Intrastate natural gas transportation is subject to regulation by state
regulatory agencies. The basis for intrastate regulation of natural gas
transportation and the degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from state to state.
Insofar as such regulation within a particular state will affect equally all
intrastate natural gas shippers within the state, we believe that the regulation
of intrastate natural gas transportation in any states in which we operate and
ship natural gas on an intrastate basis will not affect our operations any
differently than those of our competitors.

REGULATION OF TRANSPORTATION OF OIL

The transportation of oil in common carrier pipelines is also subject to
rate regulation. FERC regulates interstate oil pipeline transportation rates
under the Interstate Commerce Act. In general interstate oil pipeline rates must
be cost-based, although settlement rates agreed to by all shippers are permitted
and market-based rates may be permitted in certain circumstances. Intrastate oil
pipeline transportation rates are subject to regulation by state regulatory
commissions. The basis for intrastate oil pipeline regulation, and the degree of
regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies
from state to state. Insofar as effective interstate and intrastate rates are
equally applicable to all shippers, we believe that the regulation of oil
transportation rates will not affect our operations any differently than those
of our competitors.

Further, interstate and intrastate common carrier oil pipelines must
provide service on a non-discriminatory basis. Under this open access standard,
common carriers must offer service to all shippers requesting service on the
same terms and under the same rates. When oil pipelines operate at full
capacity, access is governed by prorationing provisions set forth in the
pipelines' published tariffs. Accordingly, we believe that access to oil
pipeline transportation services generally will be available to us to the same
extent as to our competitors.

REGULATION OF PRODUCTION

The production of oil and natural gas is subject to regulation under a wide
range of state and federal statutes, rules, orders and regulations. Federal,
state and local statutes and regulations require permits for drilling
operations, drilling bonds and reports concerning operations. Most states in
which we own and operate properties have regulations governing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing, plugging and abandonment of
wells. Many states also restrict production to the market demand for oil and
natural gas, and several states have indicated
44
<PAGE> 49

interest in revising applicable regulations. The effect of these regulations is
to limit the amount of oil and natural gas that we can produce from our wells
and to limit the number of wells or the locations at which we can drill.
Moreover, each state generally imposes a production or severance tax with
respect to production and sale of oil, natural gas and natural gas liquids
within its jurisdiction.

Some of our offshore operations are conducted on federal leases that are
administered by the MMS and are required to comply with the regulations and
orders promulgated by MMS. Among other things, we would be required to obtain
prior MMS approval for any exploration plans we pursued and our development and
production plans for these leases. The MMS regulations also establish
construction requirements for production facilities located on our federal
offshore leases and govern the plugging and abandonment of wells and the removal
of production facilities from these leases. Under limited circumstances, the MMS
could require us to suspend or terminate our operations on a federal lease.

MMS also establishes the basis for royalty payments due under federal oil
and natural gas leases through regulations issued under applicable statutory
authority. State regulatory authorities establish similar standards for royalty
due under state oil and natural gas leases. The basis for royalty established by
MMS and the state regulatory authorities is generally applicable to all oil and
natural gas lessees. Accordingly, we believe that the impact of royalty
regulation on our operations should generally be the same as the impact on our
competitors.

The failure to comply with these rules and regulations can result in
substantial penalties. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and, consequently, affects our
profitability. However, our competitors in the oil and natural gas industry are
subject to the same regulatory requirements and restrictions that affect our
operations.

ENVIRONMENTAL REGULATIONS

General. Various federal, state and local laws and regulations governing
the discharge of materials into the environment, or otherwise relating to the
protection of the environment, affect our operations and costs. In particular,
our exploration, development and production operations, our activities in
connection with storage and transportation of oil and other liquid hydrocarbons
and our use of facilities for treating, processing or otherwise handling
hydrocarbons and related wastes are subject to stringent environment regulation.
As with the industry generally, compliance with existing regulations increases
our overall cost of business. The areas affected include:

- unit production expenses primarily related to the control and limitation
of air emissions and the disposal of produced water;

- capital costs to drill exploration and development wells resulting from
expenses primarily related to the management and disposal of drilling
fluids and other oil and natural gas exploration wastes; and

- capital costs to construct, maintain and upgrade equipment and
facilities.

Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended ("CERCLA"), also known as "Superfund," imposes
liability for response costs and damages to natural resources, without regard to
fault or the legality of the original act, on some classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the Environmental Protection Agency ("EPA") and, in
some instances, third parties to act in response to threats to the public health
or the environment and to seek to recover from the responsible classes of
persons the costs they incur. In the course of our ordinary operations, we may
generate waste that may fall within CERCLA's definition of a "hazardous
substance." We may be jointly and severally liable under CERCLA or comparable
state statutes for all or part of the costs required to clean up sites at which
these wastes have been disposed.

We currently own or lease, and have in the past owned or leased, numerous
properties that for many years have been used for the exploration and production
of oil and natural gas. Although we have used
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<PAGE> 50

operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed or released on, under or
from the properties owned or leased by us or on, under or from other locations
where these wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose actions with respect to the
treatment and disposal or release of hydrocarbons or other wastes were not under
our control. These properties and wastes disposed on these properties may be
subject to CERCLA and analogous state laws. Under these laws, we could be
required:

- to remove or remediate previously disposed wastes, including wastes
disposed or released by prior owners or operators;

- to clean up contaminated property, including contaminated groundwater; or

- to perform remedial operations to prevent future contamination.

Oil Pollution Act of 1990. The Oil Pollution Act of 1990 (the "OPA") and
regulations thereunder impose liability on "responsible parties" for damages
resulting from oil spills into or upon navigable waters, adjoining shorelines or
in the exclusive economic zone of the United States. Liability under the OPA is
strict, joint and several and potentially unlimited. A "responsible party"
includes the owner or operator of an onshore facility and the lessee or
permittee of the area in which an offshore facility is located. The OPA also
requires the lessee or permittee of the offshore area in which a covered
offshore facility is located to establish and maintain evidence of financial
responsibility in the amount of $35.0 million ($10.0 million if the offshore
facility is located landward of the seaward boundary of a state) to cover
liabilities related to an oil spill for which such person is statutorily
responsible. The amount of required financial responsibility may be increased
above the minimum amounts to an amount not exceeding $150.0 million depending on
the risk represented by the quantity or quality of oil that is handled by the
facility. We carry insurance coverage we believe is customary for comparable
companies in our industry. The MMS has promulgated regulations that implement
the financial responsibility requirements of the OPA. A failure to comply with
the OPA's requirements or inadequate cooperation during a spill response action
may subject a responsible party to civil or criminal enforcement actions. We are
not aware of any action or event that would subject us to liability under the
OPA, and we believe that compliance with the OPA's financial responsibility and
other operating requirements will not have a material adverse effect on us.

Clean Water Act. The Federal Water Pollution Control Act of 1972, as
amended (the "Clean Water Act"), imposes restrictions and controls on the
discharge of produced waters and other oil and natural gas wastes into navigable
waters. These controls have become more stringent over the years, and it is
possible that additional restrictions will be imposed in the future. Permits
must be obtained to discharge pollutants into state and federal waters. Certain
state regulations and the general permits issued under the Federal National
Pollutant Discharge Elimination System program prohibit the discharge of
produced waters and sand, drilling fluids, drill cuttings and certain other
substances related to the oil and natural gas industry into certain coastal and
offshore water. The Clean Water Act provides for civil, criminal and
administrative penalties for unauthorized discharges for oil and other hazardous
substances and imposes liability on parties responsible for those discharges for
the costs of cleaning up any environmental damage caused by the release and for
natural resource damages resulting from the release. Comparable state statutes
impose liabilities and authorize penalties in the case of an unauthorized
discharge of petroleum or its derivatives, or other hazardous substances, into
state waters. We believe that our operations comply in all material respects
with the requirements of the Clean Water Act and state statutes enacted to
control water pollution.

Resources Conservation Recovery Act. The Resource Conservation and Recovery
Act of 1976, as amended ("RCRA"), is the principle federal statute governing the
treatment, storage and disposal of hazardous wastes. RCRA imposes stringent
operating requirements, and liability for failure to meet such requirements, on
a person who is either a "generator" or "transporter" of hazardous waste or an
"owner" or "operator" of a hazardous waste treatment, storage or disposal
facility. At present, RCRA includes a

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<PAGE> 51

statutory exemption that allows most oil and natural gas exploration and
production waste to be classified as nonhazardous waste. A similar exemption is
contained in many of the state counterparts to RCRA. As a result, we are not
required to comply with a substantial portion of RCRA's requirements because our
operations generate minimal quantities of hazardous wastes. At various times in
the past, proposals have been made to amend RCRA to rescind the exemption that
excludes oil and natural gas exploration and production wastes from regulation
as hazardous waste. Repeal or modification of the exemption by administrative,
legislative or judicial process, or modification of similar exemptions in
applicable state statutes, would increase the volume of hazardous waste we are
required to manage and dispose of and would cause us to incur increased
operating expenses.

Marine Protected Areas. Executive Order 13158, issued on May 26, 2000,
directs federal agencies to safeguard existing Marine Protected Areas ("MPAs")
in the United States and establish new MPAs. The order requires federal agencies
to avoid harm to MPAs to the extent permitted by law and to the maximum extent
practicable. It also directs the EPA to propose new regulations under the Clean
Water Act to ensure appropriate levels of protection for the marine environment.
Although at this time we cannot accurately assess the order's impact, it has the
potential to adversely affect our operations by restricting areas in which we
may carry out future development and exploration projects and/or causing us to
incur increased operating expenses.

Consideration of Environmental Issues in Connection with Governmental
Approvals. Our operations frequently require licenses, permits and/or other
governmental approvals. Several federal statutes, including the OCSLA, the
National Environmental Policy Act ("NEPA"), and the Coastal Zone Management Act
("CZMA") require federal agencies to evaluate environmental issues in connection
with granting such approvals and/or taking other major agency actions. OCSLA,
for instance, requires the U.S. Department of Interior ("DOI") to evaluate
whether certain proposed activities would cause serious harm or damage to the
marine, coastal or human environment. Similarly, NEPA requires DOI and other
federal agencies to evaluate major agency actions having the potential to
significantly impact the environment. In the course of such evaluations, an
agency would have to prepare an environmental assessment and, potentially, an
environmental impact statement. CZMA, on the other hand, aids states in
developing a coastal management program to protect the coastal environment from
growing demands associated with various uses, including offshore oil and natural
gas development. In obtaining various approvals from the DOI, we must certify
that we will conduct our activities in a manner consistent with an applicable
program.

Lead-Based Paints. Various pieces of equipment and structures owned by us
have been coated with lead-based paints as was customary in the industry at the
time these pieces of equipment were fabricated and constructed. These paints, in
all probability, contain lead at a concentration high enough to be considered a
regulated hazardous waste when removed. If we need to remove such paints in
connection with maintenance or other activities, their status as a regulated
hazardous waste will increase the cost of disposal. High lead levels in the
paint might also require us to institute certain administrative and/or
engineering controls required by the Occupational Safety and Health Act to
ensure worker safety during paint removal.

Air Pollution Control. The Clean Air Act and state air pollution laws
adopted to fulfill its mandates provide a framework for national, state and
local efforts to protect air quality. Our operations utilize equipment that
emits air pollutants subject to federal and state air pollution control laws.
These laws require utilization of air emissions abatement equipment to achieve
prescribed emissions limitations and ambient air quality standards, as well as
operating permits for existing equipment and construction permits for new and
modified equipment.

Air Permit at East Bay. In July 2000, we notified the Louisiana Department
of Environmental Quality ("DEQ") of our discovery of a potential non-compliance
with certain air emission requirements contained in an air permit issued for the
East Bay Central Field Facility. The air permit was issued to the previous owner
in 1997 and transferred to us when we acquired the East Bay field in April 2000.

Following meetings with DEQ, we received an Environmental Compliance Order
authorizing us to seek a modification of the permit which, among other things,
would allow us to achieve compliance with
47
<PAGE> 52

the permit's air emission requirements within 18 months of approval of the
permit modification. Non-compliance with the air permit is potentially subject
to civil penalties. Under the Environmental Compliance Order, we have agreed to
install control technology that will be designed to achieve compliance with the
existing permit. Most of the costs associated with achieving compliance with the
relevant emissions standards were already incorporated in our budget as part of
our production plans for the field and are, therefore, not expected to have a
material adverse impact on our financial condition or results of operations.
Based on available information, we do not believe that our operations will be
adversely affected by the ongoing permit and enforcement proceedings.

Naturally Occurring Radioactive Materials (NORM). NORM are materials not
covered by the Atomic Energy Act, whose radioactivity is enhanced by
technological processing such as mineral extraction or processing through
exploration and production conducted by the oil and gas industry. NORM wastes
are regulated under the RCRA framework, but primary responsibility for NORM
regulation has been a state function. Standards have been developed for worker
protection; treatment, storage and disposal of NORM waste; management of waste
piles, containers and tanks; and limitations upon the release of NORM
contaminated land for unrestricted use. We believe that our operations are in
compliance with all applicable NORM standards established by the State of
Louisiana.

Safe Drinking Water Act. Underground injection is the subsurface placement
of fluid through a well or dug-hole whose depth is greater than its width. It
can include placement through the reinjection of brine from oil and gas
production. The Safe Drinking Water Act established a regulatory framework for
underground injection, with the main goal being the protection of usable
aquifers. The primary objective of injection well operating requirements is to
ensure the mechanical integrity of the injection apparatus and to prevent
migration of fluids from the injection zone into underground sources of drinking
water. Hazardous waste injection well operations are strictly controlled, and
certain wastes, absent an exemption cannot be injected into underground
injection control wells. In Louisiana, no underground injection may take place
except as authorized by permit or rule. We currently own and operate various
underground injection wells. Failure to abide by our permits could subject us to
civil and/or criminal enforcement. We believe that we are in compliance in all
material respects with all applicable requirements of the state underground
injection control program and our permits.

EMPLOYEES

As of June 30, 2000, we had approximately 106 full-time employees,
including 22 geoscientists and engineers and 64 field personnel. Our employees
are not represented by any labor union. We consider relations with our employees
to be satisfactory. We have never experienced a work stoppage or strike.

LEGAL PROCEEDINGS

In the ordinary course of business, we are a claimant or a defendant in
various legal proceedings. We do not consider our exposure in these proceedings,
individually or in the aggregate, to be material.

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<PAGE> 53

MANAGEMENT

DIRECTORS, EXECUTIVE OFFICERS AND OTHER KEY PERSONNEL

The following table sets forth certain information regarding our directors,
executive officers and other key personnel as of August 31, 2000. There are no
family relationships among any of our directors, executive officers and other
key personnel.

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Richard A. Bachmann................... 55 Chairman, President and Chief
Executive Officer
Suzanne V. Baer....................... 52 Vice President, Finance and
Administration, and Chief Financial
Officer
Clinton W. Coldren.................... 45 Vice President, Bay Marchand Business
Unit
Wayne A. Greenwalt.................... 52 Vice President, East Bay Business Unit
John H. McCandless.................... 52 Vice President, Geology
Donald A. Olson....................... 54 Vice President, Environmental Affairs,
Reserves and Acquisitions
James E. Orth......................... 48 Vice President, Production and
Operations
Kenneth P. Smith...................... 50 Treasurer
Jean M. Stallard...................... 38 Vice President, General Counsel and
Corporate Secretary
L. Keith Vincent...................... 45 Vice President, Land
Louis E. Willhoit, Jr. ............... 51 Vice President, Geophysics
Austin M. Beutner(1).................. 40 Director
John C. Bumgarner, Jr.(1)............. 58 Director
Harold D. Carter(2)................... 61 Director
Robert D. Gershen(1).................. 47 Director
Dr. Eamon M. Kelly(2)................. 64 Director
John G. Phillips(1)................... 78 Director
Jeffrey R. Sechrest(2)................ 44 Director
</TABLE>

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

(1) Member of Compensation Committee

(2) Member of Audit Committee

Under our stockholder agreement, generally, Evercore is entitled to
nominate four persons to our board of directors. Messrs. Beutner, Bumgarner,
Carter and Sechrest were nominated pursuant to this provision. Until the date
that Energy Income Fund owns less than 10% of our common stock on a fully
diluted basis, Energy Income Fund is entitled to nominate one person to our
board of directors. Mr. Gershen was nominated pursuant to this provision. Our
other stockholders are entitled to nominate our three remaining directors.
Messrs. Bachmann and Phillips and Dr. Kelly were nominated pursuant to this
provision.

Richard A. Bachmann began organizing our company in February 1997 and has
served as our chairman, president and chief executive officer since our
incorporation in January 1998. Prior to founding our company, from 1995 to
January 1997, Mr. Bachmann served as president and chief operating officer of
The Louisiana Land and Exploration Company (LL&E), an independent oil and gas
exploration company. From 1982 to 1995, Mr. Bachmann held various positions,
including director, executive vice president, chief financial officer and senior
vice president of finance and administration of LL&E. From 1978 to 1981, Mr.
Bachmann was treasurer of Itel Corporation. Prior to 1978, Mr. Bachmann served
with Exxon International, Esso Central America, Esso InterAmerica and Standard
Oil of New Jersey. Mr. Bachmann is also a director of Penn Virginia Corporation
and Superior Energy Services, Inc. We have a contract with Production Management
Companies, Inc., a subsidiary of Superior Energy Services, Inc.

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<PAGE> 54

Suzanne V. Baer joined us in April 2000 as vice president and chief
financial officer and became vice president, finance and administration, and
chief financial officer in July 2000. Ms. Baer has 30 years of financial
management, investor relations and treasury experience in the energy industry.
From July 1998 until March 2000, Ms. Baer was vice president and treasurer of
Burlington Resources Inc. and, from October 1997 to July 1998, was vice
president and assistant treasurer of Burlington Resources. Prior to the merger
of LL&E with Burlington Resources in 1997, Ms. Baer was vice president and
treasurer of LL&E since 1995.

Clinton W. Coldren joined us in March 1998 as vice president and became
vice president of operations in June 1998. In July 2000 Mr. Coldren became vice
president, Bay Marchand business unit. Mr. Coldren has 24 years experience in
the energy industry. Immediately prior to joining us, Mr. Coldren operated a
small, family-owned project management company, Cenergy Corporation, since 1992.
Mr. Coldren managed drilling and completion operations for Consolidated Natural
Gas Company and participated in the establishment of Gulf Oil's Drilling
Technology Center. He began his career as a field production engineer, focused
on domestic operating bases, specifically the Louisiana and Texas Gulf Coast.

Wayne A. Greenwalt joined us as vice president of business development from
August 1999 to March 2000 and has been vice president, East Bay business unit,
since March 2000. Mr. Greenwalt has 28 years of experience in the energy
industry. He worked in domestic and international assignments at Pennzoil from
1992 to August 1999. Mr. Greenwalt was with LL&E from 1977 until joining
Pennzoil in 1992. Mr. Greenwalt began his career with Shell Oil as an operations
and reservoir engineer.

John H. McCandless joined us as vice president in January 1998 and became
vice president, geology, in June 1998. Mr. McCandless has 30 years of
diversified professional experience in petroleum geology. From 1976 until
joining us in 1998, he was a self-employed sole proprietor, originating and
evaluating oil and gas prospects, developing producing properties and creating
and executing 3-D seismic exploration and exploitation projects in the U.S. Gulf
Coast area. He served in various geological positions with Texaco and Southland
Royalty Company from 1970 to 1976, when he established his independent practice.

Donald A. Olson joined us as vice president in January 1998 and became vice
president, environmental affairs, reserves and acquisitions, in July 2000.
Previously, Mr. Olson was vice president of the South Timbalier 26 business unit
from June 1998. Mr. Olson has 30 years of technical experience in the energy
industry. From December 1996 until joining us, he was president of Cambridge
Consulting, an engineering and consulting firm. Mr. Olson was LL&E's engineering
manager for the Salt Dome development team from 1991 to December 1996,
engineering supervisor for the South Louisiana Onshore Area from 1986 to 1991
and a reservoir engineer from 1976 to 1986. Mr. Olson began his career with
Shell Oil as an offshore operations engineer, and after leaving LL&E.

James E. Orth joined us as vice president in January 1998 and became vice
president, production, in June 1998. In July 2000, Mr. Orth became vice
president, production and operations. Prior to joining us, Mr. Orth served with
LL&E and its successor corporation, Burlington Resources, in various positions
from 1980 to January 1998, including vice president of acquisitions and
divestitures and vice president of worldwide production. Prior to being named
vice president, Mr. Orth was general manager of LL&E's Rocky Mountain
operations. Mr. Orth began his career with Texaco as a field engineer and
engineering supervisor for Gulf Coast operations and has over 27 years of
industry experience.

Kenneth P. Smith joined us as director of finance and administration in
April 1998 and became treasurer in July 1998. Immediately prior to joining us,
Mr. Smith was manager of treasury operations at LL&E from 1988 to June 1998.
Prior to that, Mr. Smith was risk and credit manager at LL&E from 1981 to 1998.
Mr. Smith spent three years with Consolidated Natural Gas Company as an oil and
gas accountant before joining LL&E's Treasury Department in 1976.

Jean M. Stallard has been vice president, general counsel and corporate
secretary since June 1998. Prior to joining us, Ms. Stallard practiced corporate
and energy law with Patrick, Miller and Burnside, New Orleans, Louisiana from
October 1997 to June 1998. Ms. Stallard also served as assistant general counsel
of KN Energy, Inc. in Denver, Colorado from May 1997 to October 1997 and senior
counsel and

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<PAGE> 55

corporate counsel of LL&E from October 1993 to May 1997. Ms. Stallard also
practiced corporate and securities law in New York City.

L. Keith Vincent joined us as land manager in January 1999 and was
appointed vice president, land, in July 2000. Mr. Vincent was vice president,
land and legal of Great River Oil & Gas Corporation from 1994 to October 1998,
after which he performed contract work for various oil and gas exploration
companies until joining us. During Mr. Vincent's 21 year career, he also held
various managerial positions with Davis Petroleum Corporation and Transco
Exploration Company.

Louis E. Willhoit, Jr. has been vice president, geophysics, since June
1998. Mr. Willhoit also holds the position of senior vice president for and is
the majority stockholder of his D3D technology company, VTV, Incorporated. From
November 1996 to July 1998, he organized VTV and provided geophysical
consultation for Mobil's deepwater Lease Sale and Analog Field Study groups.
Prior to that he was employed by LL&E as staff geophysicist from June 1996 to
November 1996 and as senior geophysicist from 1990 to June 1996. Prior to LL&E,
he was the division geophysicist and chief geologist for Forest Oil and BWAB,
Inc., respectively, from 1977 to 1987 and provided interpretive geophysical
consulting for Amoco's North Slope/Prudeau Bay exploration group from 1974 to
1977. He started his career as a geophysicist with Shell Oil from 1972 to 1974.

Austin M. Beutner has been a director since January 2000. Mr. Beutner is a
founding partner of Evercore Partners. Mr. Beutner also serves as chief
executive officer of eCompanies-Evercore Venture Advisors LLC and as a director
of eCompanies Enterprises LLC, American Media Operations Inc. and Vertis, Inc.
Prior to founding Evercore in March 1996, Mr. Beutner served as president and
chief executive officer of The U.S. Russia Investment Fund from April 1994 until
March 1996 and a general partner of The Blackstone Group from November 1988
until April 1994.

John C. Bumgarner, Jr. has been a director since January 2000. Mr.
Bumgarner is senior vice president of corporate development and planning of The
Williams Companies, Inc., an energy and high-technology company, since 1979,
senior vice president, strategic investments and a director of Williams
Communications Group Inc. since 1999, and president of Williams International
Company since 1996. Mr. Bumgarner is also director of Management Planning
Systems, Inc., Apco Argentina Inc. and PowerTel Inc. Mr. Bumgarner is the former
treasurer of Skelly Oil.

Harold D. Carter has been a director since May 1998. Since 1995, Mr. Carter
has been an independent oil and natural gas consultant and investment advisor.
Mr. Carter is a director of Brigham Exploration Company, an independent oil and
gas exploration company, and a former president of Sabine Corporation, an
independent oil and gas exploration company.

Robert D. Gershen has been a director since May 1998. Mr. Gershen is
president of Associated Energy Managers, Inc., an investment management firm
specializing in private equity investments in the energy sector, and a managing
director of Energy Income Fund, an investment fund. Since 1989, Mr. Gershen has
managed, through Associate Energy Managers, three funds that invest in smaller
energy companies in the United States. Mr. Gershen is also a director of
Arlington Ventures.

Dr. Eamon M. Kelly has been a director since May 1998. Since July 1998, Dr.
Kelly has been a president emeritus and professor at Tulane University. From
February 1981 until June 1998, Dr. Kelly was president of Tulane University. Dr.
Kelly is chairman of the board of the National Science Foundation; professor of
international development, the Payson Center for International Development and
Technology Transfer at Tulane University; a director of Gabelli Group Capital
Partners, Inc. and Gabelli Asset Management, Inc. and a former director of LL&E.

John G. Phillips has been a director since May 1998. Since 1995, Mr.
Phillips has been an independent financial consultant. Mr. Phillips is former
chairman, president and chief executive officer of LL&E and a director of the
Whitney National Bank and Whitney Holding Corporation, with whom we have banking
relationships. Mr. Phillips retired in 1985.

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<PAGE> 56

Jeffrey R. Sechrest has been a director since January 2000. Mr. Sechrest
has been a principal of Evercore Partners since May 1997. From February 1987 to
May 1997, Mr. Sechrest was a senior managing director of Lehman Brothers. Mr.
Sechrest is also director of National Public Radio and Five Paces Ventures, L.P.

COMMITTEES OF THE BOARD OF DIRECTORS

We have two standing committees: an audit committee and a compensation
committee. Our audit committee currently consists of Messrs. Carter and Sechrest
and Dr. Kelly. Our compensation committee currently consists of Messrs. Beutner,
Bumgarner, Gershen and Phillips. Generally, so long as Evercore beneficially
owns 10% or more of our stock, Evercore will be allowed to designate at least
one member of each of our committees. Please read "Certain
Transactions -- Agreements Related to the Evercore Investment -- Stockholder
Agreement."

The audit committee reviews our auditing, accounting, financial reporting
and internal control functions and makes recommendations to the board for the
selection of independent accountants. In addition, the committee monitors the
quality of our accounting principles and financial reporting, as well as the
independence of our independent accountants. In discharging its duties, the
audit committee:

- reviews and approves the scope of the annual audit and the independent
accountant's fees;

- meets independently with our internal auditing staff, our independent
accountants and our senior management; and

- reviews the general scope of our accounting, financial reporting, annual
audit and internal audit program, matters relating to our internal
control systems and the results of the annual audit.

The compensation committee determines the compensation for all of our
executive officers, other than our chairman, president and chief executive
officer, and any other employee that the committee may designate from time to
time. Our board of directors determines the compensation of our chairman,
president and chief executive officer. In addition, the committee approves and
administers employee benefit plans.

Our board of directors may establish other committees from time to time to
facilitate the management of our business and affairs.

DIRECTOR COMPENSATION

Non-employee directors receive an annual retainer of $20,000, and meeting
fees of $1,000 for each board or committee meeting attended (if held on separate
dates), in each case to be paid, at the election of each director, up to
one-half in cash and the remainder in our common stock (valued at fair market
value) and are reimbursed for their reasonable expenses. Directors also have the
ability to defer all or a portion of their compensation.

Our board of directors adopted the 2000 stock option plan for non-employee
directors on September 12, and our shareholders approved the plan on September
15, 2000. The plan provides for automatic grants of stock options to members of
the board of directors who are not employees of the company or any subsidiary.
An initial grant of a stock option to purchase 4,000 shares of our common stock
is to be made to each non-employee director upon consummation of this offering.
An initial grant of a stock option to purchase 2,000 shares will also be made to
each person who becomes a non-employee director after the effective date upon
his or her initial election or appointment. After the initial grant, each
non-employee director will receive an additional grant of a stock option to
purchase 4,000 shares of our common stock immediately following each subsequent
annual meeting. All stock options granted under the plan will have a per share
exercise price equal to the fair market value of a share of common stock on the
date of grant (as determined by the committee appointed to administer the plan),
will be fully vested and immediately exercisable, and will expire on the earlier
of (i) ten years from the date of grant or (ii) 36 months after the optionee
ceases to be a director for any reason. For initial grants, fair market
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<PAGE> 57

value will be the public offering price. The total number of shares of our
common stock that may be issued under the plan is 250,000, subject to adjustment
in the case of certain corporate transactions and events.

Messrs. Carter and Phillips and Dr. Kelly are each a party to a stock
ownership agreement with us under which they received 15,000 common shares. Each
stock ownership agreement has provisions regarding restrictions on transfer, and
each of our director stockholders is a party to our Stockholder Agreement.
Please read "Certain Transactions -- Agreements Related to the Evercore
Investment -- Stockholder Agreement."

EXECUTIVE OFFICER COMPENSATION

Summary Compensation. The table below sets forth information regarding the
annual and other compensation for our chairman, president and chief executive
officer and our other most highly compensated executive officers for the fiscal
year ended December 31, 1999.

<TABLE>
<CAPTION>
ANNUAL COMPENSATION ALL OTHER
NAME AND PRINCIPAL POSITION(1) YEAR SALARY COMPENSATION(2)
------------------------------ ---- ------------------- ---------------
<S> <C> <C> <C>
Richard A. Bachmann, Chairman, President and Chief
Executive Officer................................. 1999 $200,000 $193,363
Clinton W. Coldren, Vice President, Bay Marchand
Business Unit..................................... 1999 100,000 40,046
John H. McCandless, Vice President, Geology......... 1999 100,000 40,151
James E. Orth, Vice President, Production and
Operations........................................ 1999 100,000 40,087
</TABLE>

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

(1) Ms. Baer, our vice president, finance and administration, and chief
financial officer, commenced employment with us in April 2000. Mr.
Greenwalt, our vice president, East Bay business unit, commenced employment
with us in August 1999.

(2) The following amounts were paid to these individuals on termination of our
royalty payment arrangement in 1999: Mr. Bachmann, $193,080; Mr. Coldren,
$39,981; Mr. McCandless, $39,981 and Mr. Orth, $39,981. The remaining
amounts represent the dollar value of term life insurance premiums paid by
us for the benefit of the executive officers.

Option Grants in Fiscal 1999. No stock options were granted to our
chairman, president and chief executive officer and our executive officers
during the fiscal year ended December 31, 1999.

Aggregated Option Exercises and Fiscal Year End Option Values. No stock
options were exercised during the fiscal year ended December 31, 1999 by our
chairman, president and chief executive officer and our executive officers and
they did not hold any unexercised stock options as of December 31, 1999.

EMPLOYMENT CONTRACTS

Pursuant to employment and stock ownership agreements, each of our
executive officers:

- has an employment agreement expiring on November 17, 2003, except for Ms.
Baer, whose employment agreement expires on April 17, 2003;

- has agreed not to compete with us for a period of two years following
termination of his or her employment; and

- must offer a predetermined number of his or her common shares to Mr.
Bachmann, Evercore or our other management stockholders on resignation or
termination for cause, except for Ms. Baer, who would retain her vested
shares and options on termination.

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<PAGE> 58

In addition, Mr. Bachmann is prohibited from soliciting or inducing our
employees to discontinue their employment with us and from interfering with our
third-party contractual relationships during and following his employment with
us and for a period of two years thereafter.

In connection with signing his or her employment and stock ownership
agreement, each of our management stockholders, except Ms. Baer, purchased stock
at approximately $0.00067 per share. Please read "Principal Stockholders." In
connection with signing her employment and stock ownership agreement, Ms. Baer
received 90,000 shares, 30,000 of which vested on execution of the agreement,
30,000 of which will vest after one year and 30,000 of which will vest after two
years, and options to purchase 375,000 shares, 150,000 at approximately $7.67
per share which vests after one year, 150,000 at approximately $8.82 per share
which vests after two years and 75,000 at approximately $10.14 per share which
vests after three years. Each option will expire five years after vesting.

In July 2000, our board of directors approved the following salaries for
Mr. Bachmann and each of our executive officers, effective August 1, 2000, and
the following special recognition bonuses payable August 1, 2000.

<TABLE>
<CAPTION>
SPECIAL
RECOGNITION
OFFICER SALARY BONUS
------- -------- -----------
<S> <C> <C>
Richard A. Bachmann......................................... $300,000 $200,000(1)
Suzanne V. Baer............................................. 185,000 50,000
Clinton W. Coldren.......................................... 160,000 50,000
Wayne A. Greenwalt.......................................... 160,000 50,000
John H. McCandless.......................................... 160,000 50,000
James E. Orth............................................... 160,000 50,000
</TABLE>

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

(1) $100,000 of Mr. Bachmann's bonus was paid August 1, 2000 and the remaining
$100,000 is payable on consummation of this offering.

BENEFIT PLAN

Our board of directors adopted the 2000 Long Term Stock Incentive Plan on
September 12, 2000, and our stockholders approved the plan on September 15,
2000. The plan provides for awards of options to purchase shares of our common
stock and performance shares. The plan is administered by the Compensation
Committee of the board of directors or another committee as may be designated by
the board of directors. The committee is authorized to select the employees and
directors of our company and our subsidiaries and affiliates who will receive
awards, to determine the types of awards to be granted to each person, and to
establish the terms of each award. The total number of shares that may be issued
under the plan is 250,000, subject to adjustment in the case of certain
corporate transactions and events. Effective at the consummation of this
offering, an option to purchase 10,000 shares was granted to one of our
non-executive officers.

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PRINCIPAL STOCKHOLDERS

The following table sets forth information with respect to the beneficial
ownership of our common stock as of June 30, 2000:

- each person known by us to own beneficially more than 5% of our common
stock;

- each of our directors;

- our chairman, president and chief executive officer and executive
officers; and

- all of our directors and executive officers as a group.

The amounts and percentages of common stock beneficially owned are reported
on the basis of regulations of the SEC governing the determination of beneficial
ownership of securities. Under the rules of the SEC, a person is deemed to be a
beneficial owner of a security if that person has or shares voting power, which
includes the power to vote or to direct the voting of the security, or
investment power, which includes the power to dispose of or to direct the
disposition of the security. Unless otherwise indicated below, each beneficial
owner named in the table below has sole voting and sole investment power with
respect to all shares beneficially owned, subject to community property laws
where applicable. Percentage of beneficial ownership of common stock before the
offering is based on 17,823,289 shares of common stock outstanding and the
percentage of beneficial ownership of common stock after the offering is based
on 27,057,489 shares of common stock outstanding. Please read "Capitalization"
and "Description of Capital Stock."

<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
----------------------------------------
BEFORE OFFERING AFTER OFFERING(1)
------------------- -------------------
BENEFICIAL OWNER SHARES PERCENT SHARES PERCENT
---------------- --------- ------- --------- -------
<S> <C> <C> <C> <C>
Evercore Capital Partners L.P. and affiliates(2)....... 9,414,139 52.8% 9,414,139 34.8%
65 East 55th Street
New York, New York 10022
Energy Income Fund, L.P.(3)............................ 4,223,280 23.7 5,151,330 19.0
136 Dwight Road
Longmeadow, Massachusetts 01106
Richard A. Bachmann(4)................................. 1,525,230 8.6 2,526,899 9.3
Energy Partners, Ltd.
201 St. Charles Avenue, Suite 3400
New Orleans, Louisiana 70170
Austin M. Beutner(2)(5)................................ -- * 4,000 *
John C. Bumgarner, Jr.(5)(6)........................... -- * 4,000 *
Harold D. Carter(4)(5)................................. 8,295 * 17,459 *
Robert D. Gershen(3)(5)................................ -- * 4,000 *
Dr. Eamon M. Kelly(4)(5)............................... 8,295 * 17,459 *
John G. Phillips(4)(5)................................. 8,295 * 17,459 *
Jeffrey R. Sechrest(2)(5).............................. -- * 4,000 *
Suzanne V. Baer........................................ 30,000 * 30,000 *
Clinton W. Coldren(4).................................. 248,895 1.4 455,426 1.7
Wayne A. Greenwalt(4)(7)............................... 248,895 1.4 455,426 1.7
John H. McCandless(4).................................. 248,895 1.4 455,426 1.7
James E. Orth(4)(8).................................... 248,895 1.4 455,426 1.7
All directors and executive officers as a group (13 2,575,695 14.5 4,446,980 16.4
persons).............................................
</TABLE>

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

* Represents beneficial ownership of less than 1%.

(1) Please read "Capitalization" for a description of the shares of common stock
to be outstanding after the offering.

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<PAGE> 60

(2) Of these shares, 9,329,839 are issuable on conversion of preferred stock,
which will occur automatically on completion of this offering. These shares
are beneficially owned as follows:

- Evercore Capital Partners, L.P. -- 6,130,152;

- Evercore Capital Offshore Partners L.P. -- 1,619,616;

- Evercore Capital Partners (NQ) L.P. -- 1,476,723; and

- Evercore Co-Investment Partnership L.P. -- 187,648.

Messrs. Beutner and Sechrest, each a principal of Evercore, disclaim
beneficial ownership of shares of our capital stock owned by Evercore,
other than an economic interest in the following shares beneficially owned
by Evercore Co-Investment Partnership L.P.: Mr. Beutner -- 66,056 and Mr.
Sechrest -- 30,135.

(3) A warrant held by Energy Income Fund to purchase 928,050 shares of common
stock will become exercisable upon completion of this offering. Mr. Gershen,
a managing director of Energy Income Fund, disclaims beneficial ownership of
all shares held by Energy Income Fund.

(4) The "After Offering" column includes shares which will be released from
escrow on completion of this offering.

(5) On completion of this offering, non-employee directors will receive options
to acquire 4,000 shares of our common stock. Each of Mr. Beutner and Mr.
Sechrest have ceded rights to his options to Evercore.

(6) Mr. Bumgarner has an economic interest in 15,548 shares of common stock
beneficially owned by Evercore Co-Investment Partnership L.P.

(7) A trust of which Mr. Greenwalt is one of the settlors and one of his
children is the beneficiary has an option to acquire 105,000 shares of his
common stock.

(8) A trust of which Mr. Orth is one of the settlors and his children are the
beneficiaries has an option to acquire 120,000 shares of his common stock.

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<PAGE> 61

CERTAIN TRANSACTIONS

AGREEMENTS WITH ENERGY INCOME FUND

On April 15, 1998, we entered into a financing agreement with Energy Income
Fund and, pursuant to the financing agreement, as amended, Energy Income Fund
made a $25.0 million development loan to us, secured by substantially all of our
assets as collateral, to finance a portion of the costs related to the
development, production and management of various oil and natural gas properties
and for working capital. In connection with this financing agreement, Energy
Income Fund acquired 7,500,000 shares of our common stock. In connection with
the Evercore private placement in November 1999 (described below), $15.0 million
of this loan was repaid, 3,291,720 of Energy Income Fund's common shares were
canceled and we gave Energy Income Fund a warrant to purchase up to 928,050
shares of our common stock at a price of approximately $6.50 per share (or
through a cashless exercise) concurrent with or after this offering for up to 60
days. Please read "Principal Stockholders."

AGREEMENTS RELATED TO THE EVERCORE INVESTMENT

On November 17, 1999, we completed a private placement of our convertible
preferred shares for $60.0 million to Evercore and its affiliates. These
preferred shares, other than the Series C preferred shares, will be
automatically converted into our common shares on completion of this offering.
We will redeem the Series C preferred shares for $4.5 million (assuming an
offering date of September 30, 2000) immediately following consummation of this
offering.

The following is a description of the agreements that we entered into with
Evercore and its affiliates in connection with this private placement.

STOCKHOLDER AGREEMENT

Board of Directors Composition. Under the Stockholder Agreement among us
and our stockholders, generally our board of directors must be composed of eight
directors until the earlier to occur of (1) the date that Evercore's aggregate
common stock ownership interest is less than one-third of the common stock
ownership interest held by Evercore on the date of the Evercore private
placement, or, if earlier, the date on which Evercore has received $120.0
million in net proceeds as a result of disposition of its preferred and/or
common stock (the "Transition Date") and (2) the date that any entity acquires
80% or more of our common stock. Generally, Evercore is entitled to nominate
four persons to our board of directors. Messrs. Beutner, Bumgarner, Carter and
Sechrest were nominated pursuant to this provision. Until the date that Energy
Income Fund owns less than 10% of our common stock on a fully diluted basis,
Energy Income Fund is entitled to nominate one person to our board of directors.
Mr. Gershen was nominated pursuant to this provision. Our other stockholders are
entitled to nominate our three remaining directors. Messrs. Bachmann and
Phillips and Dr. Kelly were nominated pursuant to this provision. Generally, so
long as Evercore beneficially owns 10% or more of us, Evercore will be allowed
to designate at least one member of each of our committees composed of three
members and a number of members on committees composed of greater than three
members equal to Evercore's proportion of directors on our board of directors.

Restrictions. Until the Transition Date, the Stockholder Agreement
generally provides restrictions on:

- consolidation or merger by us;

- modification of our certificate of incorporation, bylaws or any preferred
stock certificate of designation or otherwise change the rights of our
capital stock;

- our ability to issue securities;

- modification of the size or quorum requirements of our board of directors
(see above);

- liquidation, dissolution, winding-up or discontinuance of us;

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<PAGE> 62

- declaration of dividends and redemption of our securities except as
required by the terms of the preferred stock;

- redemption, purchase or other acquisition of our securities;

- acquisitions, joint ventures or partnerships, dispositions of assets,
incurrence of indebtedness and creation of liens in excess of specified
amounts;

- increasing compensation, creating or amending employment agreements or
awarding stock or stock options;

- approving capital and operating budgets or amending those budgets in
excess of specified limits;

- engaging in oil and/or natural gas price hedging transactions; and

- other matters, including affiliate transactions.

Upon completion of this offering, some provisions of our Stockholder
Agreement will terminate, including those relating to Evercore's rights of first
offer, rights to condition sales of stockholder's shares upon the buyer
purchasing a pro-rata portion of Evercore's shares, rights to require
stockholders to sell their shares when, and on the same terms that, Evercore
sells its shares (except that the latter rights will remain in effect with
respect to Mr. Bachmann and Energy Income Fund) and rights to issuances of
shares to Evercore for breaches of representations and warranties made at the
time of the private placement, and some provisions of the employment and stock
ownership agreements, including a right of Evercore to buy shares from Mr.
Bachmann and a right of Mr. Bachmann to sell a specified number of shares owned
by him to Evercore.

Escrowed and Bonus Shares. Under the Stockholder Agreement, each management
and director stockholder deposited approximately 45% of the shares owned by him
or her into escrow. Of the shares deposited, 2,545,500 will vest upon completion
of this offering. An additional 139,500 shares, will vest at the same time for
non-executive officer employees selected by our board of directors and approved
by Evercore. However, 128,850 of these shares will not be issued because
employees have chosen to defer their issuance.

Monitoring Fee. Until termination of the Stockholder Agreement, which will
occur when Evercore beneficially owns less than 10% of us, we will pay an
affiliate of Evercore an annual monitoring fee of $250,000.

REGISTRATION RIGHTS AGREEMENT

Under the Registration Rights Agreement among us and our stockholders,
Evercore has the right to require us to register their shares with the SEC so
that those shares may be publicly resold or to include their shares in any
registration statement that we file, other than the registration statement
relating to this offering.

Demand Registration Rights. At any time after six months following the
closing date of this offering, Evercore can request that we file a registration
statement so that they can publicly sell their common shares and the shares of
other stockholders with registration rights. The underwriters of any
underwritten offering will have the right to limit the number of shares to be
included in the filed registration statement.

Piggyback Registration Rights. If we register any common shares for public
sale other than shares pursuant to this offering, all stockholders prior to this
offering will have the right to include their shares in that registration
statement. The underwriters of any underwritten offering will have the right to
limit the number of shares to be included in the filed registration statement.

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<PAGE> 63

Expenses of Registration. We will pay all expenses relating to any demand
or piggyback registration. However, we will not pay the underwriting discounts
and selling commissions applicable to shares registered pursuant to these
registration rights.

Expiration of Registration Rights. The registration rights will terminate
for a particular stockholder if that holder can resell its common stock without
the imposition of the volume, manner of sale and holding period limitations of
Rule 144 under the Securities Act.

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<PAGE> 64

DESCRIPTION OF CAPITAL STOCK

CAPITAL STOCK

AUTHORIZED CAPITAL STOCK

Under our certificate of incorporation, our authorized capital stock is
51,700,000 shares, of which 50,000,000 shares are common stock, par value $0.01
per share, and 1,700,000 shares are preferred stock, par value $1.00 per share.
As of June 30, 2000, we had 11,798,280 shares of common stock 500,000 shares of
Series A preferred stock, 100,000 shares of Series B preferred stock and no
shares of Series C preferred stock outstanding. Upon consummation of this
offering, we will have 27,057,489 shares of common stock and no shares of
preferred stock outstanding. Assuming this offering had been completed on June
30, 2000, the shares of Series A and B preferred stock would have converted into
9,329,839 shares of common stock. Please read "Capitalization" for a description
of the shares of common stock that will be outstanding immediately following
this offering. There were 37 holders of record of our common stock as of June
30, 2000.

COMMON STOCK

Holders of common stock are entitled to one vote per share with respect to
each matter presented to our stockholders on which the holders of common stock
are entitled to vote. Except as may be provided in connection with any preferred
stock in a certificate of designation filed pursuant to the Delaware General
Corporation Law, or the DGCL, or as may otherwise be required by law or our
certificate of incorporation, the common stock is our only capital stock
entitled to vote in the election of directors and on all other matters presented
to our stockholders; provided that, except as required by law or our certificate
of incorporation, holders of common stock are not entitled to vote on any
amendment to our certificate of incorporation that solely relates to the terms
of any outstanding series of preferred stock or the number of shares of such
series and does not affect the number of authorized shares of preferred stock or
the terms of the common stock if the holders of preferred stock are entitled to
vote thereon. The common stock does not have cumulative voting rights.

Subject to the prior rights of holders of preferred stock, if any, holders
of common stock are entitled to receive dividends as may be lawfully declared
from time to time by our board of directors. Upon our liquidation, dissolution
or winding up, whether voluntary or involuntary, holders of common stock will be
entitled to receive such assets as are available for distribution to our
stockholders after there shall have been paid or set apart for payment the full
amounts necessary to satisfy any preferential or participating rights to which
the holders of each outstanding series of preferred stock are entitled by the
express terms of the series.

PREFERRED STOCK

Our board is empowered, without approval of our stockholders, to cause
shares of preferred stock to be issued from time to time in one or more series,
with the numbers of shares of each series and the terms of the shares of each
series as fixed by our board. Among the specific matters that may be determined
by our board are:

- the designation of each series;

- the number of shares of each series;

- the rights in respect of dividends, if any;

- whether dividends, if any, shall be cumulative or non-cumulative;

- the terms of redemption, if any;

- the rights in the event of any voluntary or involuntary liquidation,
dissolution or winding up of our affairs;

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- rights and terms of conversion or exchange, if any;

- restrictions on the issuance of shares of the same series or any other
series, if any; and

- voting rights, if any.

Upon completion of this offering, no shares of preferred stock will be
outstanding and we have no current plans to issue preferred stock. The issuance
of shares of preferred stock, or the issuance of rights to purchase preferred
stock, could be used to discourage an unsolicited acquisition proposal. For
example, a business combination could be impeded by the issuance of a series of
preferred stock containing class voting rights that would enable the holder or
holders of such series to block any such transaction. Alternatively, a business
combination could be facilitated by the issuance of a series of preferred stock
having sufficient voting rights to provide a required percentage vote of our
stockholders. In addition, under some circumstances, the issuance of preferred
stock could adversely affect the voting power and other rights of the holders of
common stock. Although prior to issuing any series of preferred stock our board
is required to make a determination as to whether the issuance is in the best
interests of our stockholders, our board could act in a manner that would
discourage an acquisition attempt or other transaction that some, or a majority,
of our stockholders might believe to be in their best interests or in which our
stockholders might receive a premium for their stock over prevailing market
prices of such stock. Our board does not at present intend to seek stockholder
approval prior to any issuance of currently authorized preferred stock, unless
otherwise required by law or applicable stock exchange requirements.

REGISTRATION RIGHTS

We granted all stockholders prior to this offering registration rights with
respect to the shares of our common stock that each of them owns and will own
upon the completion of this offering. For a more complete description of the
terms of the registration rights agreement, please read "Certain
Transactions -- Agreements Related to the Evercore Investment -- Registration
Rights Agreement."

ANTI-TAKEOVER PROVISIONS

SECTION 203 OF THE DELAWARE GENERAL CORPORATION LAW

We are a Delaware corporation and, upon the completion of this offering,
will be subject to Section 203 of the DGCL. Generally, Section 203 prohibits a
publicly held Delaware corporation from engaging in a "business combination"
with an "interested stockholder" for a period of three years after the time such
stockholder became an interested stockholder unless, as described below, certain
conditions are satisfied. Thus, it may make acquisition of control of our
company more difficult. Please read "-- Certain Limitations on Changes of
Control" below. The prohibitions in Section 203 of the DGCL do not apply if:

- prior to the time the stockholder became an interested stockholder, the
board of directors of the corporation approved either the business
combination or the transaction that resulted in the stockholder becoming
an interested stockholder;

- upon consummation of the transaction that resulted in the stockholder
becoming an interested stockholder, the interested stockholder owned at
least 85% of the voting stock of the corporation outstanding at the time
the transaction commenced, subject to certain limitations; or

- at or subsequent to the time the stockholder became an interested
stockholder, the business combination is approved by the board of
directors and authorized at an annual or special meeting of stockholders,
and not by written consent, by the affirmative vote of at least 66 2/3%
of the outstanding voting stock that is not owned by the interested
stockholder.

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Under Section 203 of the DGCL, a "business combination" includes:

- any merger or consolidation of the corporation with the interested
stockholder;

- any sale, lease, exchange or other disposition, except proportionately as
a stockholder of such corporation, to or with the interested stockholder,
of assets of the corporation having an aggregate market value equal to
10% or more of either the aggregate market value of either all the assets
of the corporation or the aggregate market value of all the outstanding
stock of the corporation;

- certain transactions resulting in the issuance or transfer by the
corporation of stock of the corporation to the interested stockholder;

- certain transactions involving the corporation which have the effect of
increasing the proportionate share of the stock of any class or series of
the corporation which is owned by the interested stockholder; or

- certain transactions in which the interested stockholder receives
financial benefits provided by the corporation.

Under Section 203 of the DGCL, an "interested stockholder" generally is:

- any person that owns 15% or more of the outstanding voting stock of the
corporation;

- any person that is an affiliate or associate of the corporation and was
the owner of 15% or more of the outstanding voting stock of the
corporation at any time within the three-year period prior to the date on
which it is sought to be determined whether such person is an interested
stockholder; and

- the affiliates or associates of any such person.

Because Evercore will have owned more than 15% of our voting stock before
we become a public company in this offering, Section 203 of the DGCL, by its
terms, will not be applicable to business combinations with Evercore even though
Evercore owns 15% or more of our outstanding stock. If any other person acquires
15% or more of our outstanding stock after the completion of this offering, such
person will be subject to the provisions of Section 203 of the DGCL.

BYLAWS

Our bylaws provide that, in order for our stockholders to take action by
written consent in lieu of a meeting, the consent be signed by the holders of
shares of capital stock having not less than the greater of (1) the minimum
number of votes that would be necessary to authorize the taking of the action at
a meeting at which the holders of all shares entitled to be voted thereon were
present and voted or (2) 85% of the total number of votes of the then
outstanding shares of our capital stock entitled to vote. Our bylaws also
prohibit stockholders from calling meetings. Our bylaws further establish an
advance notice procedure with regard to business to be brought before an annual
or special meeting of our stockholders and with regard to the nomination, other
than by or at the direction of our board of directors, of candidates for
election as directors. Although our bylaws do not give the board of directors
any power to approve or disapprove stockholder nominations for the election of
directors or proposals for action, they may have the effect of precluding a
contest for the election of directors or the consideration of stockholder
proposals if the proper procedures are not followed. They may also discourage or
deter a third party from conducting a solicitation of proxies to elect its own
slate of directors or to approve its proposal without regard to whether
consideration of such nominees or proposals might be harmful or beneficial to us
and our stockholders. An affirmative vote by the holders of more than two thirds
of our common stock is required to modify the advance notice procedure.

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CERTAIN LIMITATIONS ON CHANGE OF CONTROL

The foregoing provisions of our organizational documents and the provisions
of Section 203 of the DGCL could have the following effects, among others:

- delaying, deferring or preventing a change of control of our company;

- delaying, deferring or preventing the removal of our existing management;

- deterring potential acquirers from making an offer to our stockholders;
and

- limiting any opportunity of our stockholders to realize premiums over
prevailing market prices of our common stock in connection with offers by
potential acquirors.

This could be the case notwithstanding that a majority of our stockholders might
benefit from such a change of control or offer. Please read "Certain
Transactions -- Agreements Related to the Evercore Investment" for a discussion
of Evercore's right to approve transactions that would result in a change of
control.

LIMITATION ON LIABILITY AND INDEMNIFICATION OF DIRECTORS AND OFFICERS

Our certificate of incorporation provides, as authorized by Section
102(b)(7) of the DGCL, that a director will not be personally liable to us or
our stockholders for monetary damages for breach of fiduciary duty as a
director, except for liability imposed by law, as in effect from time to time:

- for any breach of the director's duty of loyalty to us or our
stockholders;

- for acts or omissions not in good faith or which involved intentional
misconduct or a knowing violation of law;

- for unlawful payments of dividends or unlawful stock repurchases or
redemptions as provided in Section 174 of the DGCL; or

- for any transaction from which the director derived an improper personal
benefit.

Section 145 of the DGCL provides that a Delaware corporation may indemnify
any persons who were, are or are threatened to be made, parties to any
threatened, pending or completed action, suit or proceeding, whether civil,
criminal, administrative or investigative, other than a "derivative" action by
or in the right of the corporation, by reason of the fact that the person is or
was a director, officer, employee or agent of the corporation, or is or was
serving at the request of the corporation as a director, officer, employee or
agent of another corporation or enterprise. The indemnity may include expenses
(including attorneys' fees), judgments, fines and amounts paid in settlement
actually and reasonably incurred by the person in connection with the action,
suit or proceeding, provided the person acted in good faith and in a manner he
reasonably believed to be in or not opposed to the corporation's best interests
and, with respect to any criminal action or proceeding, had no reasonable cause
to believe that his conduct was unlawful. A similar standard of care is
applicable in the case of derivative actions, except that no indemnification
shall be made where the person is adjudged to be liable to the corporation
unless and only to the extent that the Court of Chancery of the State of
Delaware or the court in which such action was brought determines that the
person is fairly and reasonably entitled to indemnity and expenses.

Our certificate of incorporation and bylaws provide that we will indemnify
our directors, officers, employees and agents to the fullest extent permitted by
the DGCL, and we will advance expenses to our directors, officers, employees and
agents in connection with legal proceedings, subject to limited exceptions.

We have and will retain customary insurance policies under which coverage
is provided for payments made by us to our directors and officers in respect of
the indemnification provisions in our certificate of incorporation and bylaws.
We believe that these indemnification provisions and insurance are necessary to
attract and retain qualified directors and officers.

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The limitation on liability and indemnification provisions in our
certificate of incorporation and bylaws may not be enforceable against us if
someone challenges these provisions. Nonetheless, these provisions may
discourage our stockholders from bringing a lawsuit against directors for breach
of their fiduciary duty. These provisions may also have the effect of reducing
the likelihood of derivative litigation against our directors and officers, even
though such an action, if successful, might otherwise benefit us and our
stockholders. Furthermore, a stockholder's investment may be adversely affected
to the extent we pay costs of settlement and damage awards against directors and
officers pursuant to these indemnification provisions.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the common stock is . The
transfer agent's address is
and its telephone number is .

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<PAGE> 69

SHARES ELIGIBLE FOR FUTURE SALE

GENERAL

Prior to this offering there has been no public market for our common
stock, and no predictions can be made regarding the effect, if any, that sales
of substantial amounts of our common stock, or the perception that such sales
may occur, will have on the prevailing market price of our common stock. Sales
of substantial amounts of our common stock in the public market after the
restrictions lapse or are waived could adversely affect the prevailing market
price.

Upon completion of this offering, we expect to have 27,057,489 shares of
common stock outstanding. The shares of common stock being sold in this offering
will be freely tradable without restriction or registration under the Securities
Act, except for shares, if any, held by our "affiliates," as that term is
defined in the Securities Act. Persons who may be deemed to be our affiliates
generally include individuals or entities that control, are controlled by, or
are under common control with, our company and may include our directors and
officers, as well as our significant stockholders. The remaining shares of our
common stock held by our other stockholders are "restricted securities," as that
term is defined in the Securities Act. These shares are eligible for public sale
only if registered under the Securities Act or sold in accordance with Rules 144
or 144(k) under the Securities Act.

All of our directors, officers, Evercore, Energy Income Fund and we have
agreed that, for a period of 180 days from the date of this prospectus, we will
not, without the prior written consent of Merrill Lynch, dispose of or hedge any
shares of our common stock or any securities convertible into, or exercisable or
exchangeable for, our common stock. Merrill Lynch, in its sole discretion, may
release any of these securities subject to the lock-up agreements at any time
without notice.

RULE 144

In general, under Rule 144 as currently in effect, beginning 90 days after
the date of this prospectus, a person, or persons whose shares are aggregated,
including one of our affiliates, who beneficially owns "restricted securities"
may not sell those securities until they have been beneficially owned for at
least one year. Thereafter, the person would be entitled to sell within any
three-month period a number of shares that does not exceed the greater of:

- 1% of the number of shares of common stock then outstanding, which will
equal approximately 270,575 shares immediately after the offering; or

- the average weekly trading volume of our common stock on the New York
Stock Exchange during the four calendar weeks preceding the filing with
the SEC of a notice on the SEC's Form 144 with respect to such sale.

Sales under Rule 144 are also subject to certain manner of sale and notice
requirements and to the availability of current public information about us.

RULE 144(k)

Under Rule 144(k), a person who is not, and has not been at any time during
the 90 days preceding a sale, one of our affiliates and who has beneficially
owned the shares proposed to be sold for at least two years, including the
holding period of any prior owner except one of our affiliates, is entitled to
sell these shares without complying with the manner of sale, public information,
volume limitation or notice provisions of Rule 144.

BENEFIT PLANS

Following the completion of this offering, we intend to file a registration
statement on Form S-8 under the Securities Act covering shares of our common
stock reserved for issuance under our 2000 long term stock incentive plan, our
directors' stock option and deferral plans, and other rights to acquire shares.
We
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<PAGE> 70

expect the registration statement to be filed soon after the date of this
prospectus and automatically to become effective upon filing. Accordingly, our
common stock registered under the registration statement will, subject to
vesting provisions and volume limitations under the Securities Act applicable to
our affiliates, be available for sale in the open market immediately, subject to
the 180-day lock-up agreements described above.

REGISTRATION RIGHTS OF EVERCORE

We have entered into a registration rights agreement with Evercore under
which Evercore may require us to register under the Securities Act all or any
portion of our common stock that it holds and will hold upon the completion of
this offering. Any of Evercore's shares of our common stock registered pursuant
to the registration rights agreement would be eligible for immediate resale in
the public markets without restriction. For a more complete description of the
terms of the registration rights agreement, please read "Certain
Transactions -- Agreements Related to the Evercore Investment -- Registration
Rights Agreement."

Any sales of substantial amounts of our common stock in the public markets,
or the perception that such sale may occur, could adversely affect the market
price of our common stock. Please read "Risk Factors -- The market price of our
common stock could be adversely affected by sales of substantial amounts of our
common stock in the public markets."

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<PAGE> 71

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS
FOR NON-U.S. HOLDERS OF OUR COMMON STOCK

GENERAL

The following discussion summarizes the U.S. federal income and estate tax
consequences of the ownership and disposition of our common stock by a
beneficial owner thereof that is a non-U.S. holder. A non-U.S. holder is a
person or entity that, for U.S. federal income tax purposes, is a non-resident
alien individual, a foreign corporation or a foreign estate or trust.

This discussion is based on the Internal Revenue Code of 1986, as amended,
and administrative interpretations as of the date of this prospectus, all of
which are subject to change, including changes with retroactive effect. This
discussion does not address all aspects of U.S. federal income and estate
taxation that may be relevant to non-U.S. holders, including non-U.S. holders
who are pass-through entities, in light of their particular circumstances and
does not address any tax consequences arising under the laws of any state, local
or foreign jurisdiction. Prospective holders of our common stock should consult
their tax advisors with respect to the particular tax consequences to them of
owning and disposing of our common stock, including the consequences under the
laws of any state, local or foreign jurisdiction.

DIVIDENDS

Subject to the discussion below, dividends paid to a non-U.S. holder of our
common stock generally will be subject to withholding tax at a 30% rate or a
lower rate as may be specified by an applicable income tax treaty. For purposes
of determining whether tax is to be withheld at a 30% rate or at a reduced rate
as specified by an income tax treaty, we ordinarily will presume that dividends
paid on or before December 31, 2000 to an address in a foreign country are paid
to a resident of that country absent knowledge that this presumption is not
warranted.

For dividends paid after December 31, 2000, in order to obtain a reduced
rate of withholding under an income tax treaty a non-U.S. holder will generally
be required to provide a U.S. Internal Revenue Service Form W-8BEN certifying
the non-U.S. holder's entitlement to benefits under an applicable income tax
treaty. Special rules determine whether, for purposes of determining the
applicability of an income tax treaty, dividends paid to a non-U.S. holder that
is an entity should be treated as paid to the entity or those holding an
interest in the entity.

No withholding tax applies to dividends paid to a non-U.S. holder that are
effectively connected with the non-U.S. holder's conduct of a trade or business
within the United States if an Internal Revenue Service Form W-8ECI stating that
the dividends are so connected is filed with us or our paying agent. Instead,
the effectively connected dividends will be subject to regular U.S. income tax
in the same manner as if the non-U.S. holder were a U.S. resident unless an
applicable income tax treaty exemption applies. A non-U.S. corporation receiving
effectively connected dividends may also be subject to an additional branch
profits tax. This tax is imposed, under some circumstances, at a rate of 30%, or
a lower rate as may be specified by an applicable income tax treaty, of the
non-U.S. corporation's effectively connected earnings and profits, subject to
certain adjustments.

Generally, we must report to the U.S. Internal Revenue Service the amount
of dividends paid, the name and address of the recipient, and the amount, if
any, of tax withheld. A similar report is sent to the recipient of the dividend.
Pursuant to income tax treaties or some other agreements, the U.S. Internal
Revenue Service may make its reports available to tax authorities in the
recipient's country of residence.

Dividends paid to a non-U.S. holder at an address within the U.S. may be
subject to backup withholding imposed at a rate of 31% if the non-U.S. holder
fails to establish that it is entitled to an exemption from backup withholding
or to provide a correct taxpayer identification number and some other
information to us or our paying agent.

As discussed elsewhere in this prospectus, we do not anticipate paying any
cash or dividends on our common stock in the future.
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<PAGE> 72

GAIN ON DISPOSITION OF OUR COMMON STOCK

A non-U.S. holder generally will not be subject to U.S. federal income tax
with respect to gain realized on a sale or other disposition of our common stock
unless:

- the gain is effectively connected with a trade or business of the
non-U.S. holder in the United States;

- in the case of a non-U.S. holder who is a non-resident alien individual
and who holds the common stock as a capital asset, this individual is
present in the United States for 183 or more days in the taxable year of
the disposition;

- the non-U.S. holder is subject to tax pursuant to the provisions of the
Internal Revenue Code regarding the taxation of U.S. expatriates; or

- we are or have been a U.S. real property holding corporation within the
meaning of Section 897(c)(2) of the Internal Revenue Code at any time
within the shorter of the five-year period preceding the sale or
disposition or the period during which the non-U.S. holder has held the
common stock.

We believe that it is likely that we are, or will be treated as, a United
States real property holding corporation within the meaning of Section 897(c)(2)
of the Internal Revenue Code. Even if we are treated as a United States real
property holding corporation, gain realized by a non-U.S. holder on a
disposition of our common stock will not be subject to a U.S. federal income tax
so long as:

- the non-U.S. holder at all times is deemed to have beneficially owned no
more than 5% of the common stock, taking into account for this purpose
certain constructive ownership rules; and

- our common stock at all times is regularly traded on an established
securities market, within the meaning of Section 897(c)(3) of the Code
and the Treasury Regulations thereunder.

There can be no assurance that our common stock qualifies or will continue to
qualify as regularly traded on an established securities market.

INFORMATION REPORTING REQUIREMENTS AND BACKUP WITHHOLDING ON DISPOSITION OF OUR
COMMON STOCK

Under current U.S. federal income tax law, information reporting and backup
withholding imposed at a rate of 31% will apply to the proceeds of a disposition
of our common stock effected by or through a U.S. office of a broker unless the
disposing holder certifies as to its non-U.S. status or otherwise establishes an
exemption from withholding. Generally, U.S. information reporting and backup
withholding will not apply to a payment of disposition proceeds where the
transaction is effected outside the U.S. through a non-U.S. office of a non-U.S.
broker. However, U.S. information reporting requirements, but not backup
withholding, will apply to a payment of disposition proceeds where the
transaction is effected outside the United States by or through a non-U.S.
office of a broker that is either:

- a U.S. person;

- a foreign person which derives 50% or more of its gross income for
certain periods from the conduct of a trade or business in the United
States;

- a controlled foreign corporation for U.S. federal income tax purposes; or

- in the case of payments made after December 31, 2000, a foreign
partnership with certain connections to the United States, in each case
unless the broker has documentary evidence that the holder is a non-U.S.
holder and that some conditions are met or that the holder otherwise
established an exemption from withholding.

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<PAGE> 73

Backup withholding is not an additional tax. Rather, the tax liability of
persons subject to backup withholding will be reduced by the amount of tax
withheld. If withholding results in an overpayment of taxes, a refund may be
obtained, provided that the required information is furnished to the U.S.
Internal Revenue Service.

FEDERAL ESTATE TAX

An individual non-U.S. holder who is treated as the owner of, or has made
certain lifetime transfers of, an interest in our common stock will be required
to include the value of the common stock in his gross estate for U.S. federal
estate tax purposes, and may be subject to U.S. federal estate tax unless an
applicable estate tax treaty provides otherwise.

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<PAGE> 74

UNDERWRITING

We intend to offer the shares in the U.S. and Canada through the U.S.
underwriters and elsewhere through the international managers. Merrill Lynch,
Pierce, Fenner & Smith Incorporated and UBS Warburg LLC are acting as U.S.
representatives of the U.S. underwriters named below. Subject to the terms and
conditions described in a U.S. purchase agreement among us and the U.S.
underwriters, and concurrently with the sale of 1,150,000 shares to the
international managers, we have agreed to sell to the U.S. underwriters, and the
U.S. underwriters severally have agreed to purchase from us, the number of
shares listed opposite their names below.

<TABLE>
<CAPTION>
NUMBER OF
U.S. UNDERWRITER SHARES
------------------------------------------------------------ ---------
<S> <C>
Merrill Lynch, Pierce, Fenner & Smith
Incorporated...................................
UBS Warburg LLC.............................................
Donaldson, Lufkin & Jenrette Securities Corporation.........
Howard Weil, a Division of Legg Mason Wood Walker, Inc......
--------
Total.......................................... 4,600,000
========
</TABLE>

We have also entered into an international purchase agreement with the
international managers for sale of the shares outside the U.S. and Canada for
whom Merrill Lynch International and UBS AG are acting as lead managers. Subject
to the terms and conditions in the international purchase agreement, and
concurrently with the sale of 4,600,000 shares to the U.S. underwriters pursuant
to the U.S. purchase agreement, we have agreed to sell to the international
managers, and the international managers severally have agreed to purchase
1,150,000 shares from us. The initial public offering price per share and the
total underwriting discount per share are identical under the U.S. purchase
agreement and the international purchase agreement.

The U.S. underwriters and the international managers have agreed to
purchase all of the shares sold under the U.S. and international purchase
agreements if any of these shares are purchased. If an underwriter defaults, the
U.S. and international purchase agreements provide that the purchase commitments
of the non-defaulting underwriters may be increased or the purchase agreements
may be terminated. The closings for the sale of shares to be purchased by the
U.S. underwriters and the international managers are conditioned on one another.

We have agreed to indemnify the U.S. underwriters and the international
managers against certain liabilities, including liabilities under the Securities
Act, or to contribute to payments the U.S. underwriters and international
mangers may be required to make in respect of those liabilities.

The underwriters are offering the shares, subject to prior sale, when, as
and if issued to and accepted by them, subject to approval of legal matters by
their counsel, including the validity of the shares, and other conditions
contained in the purchase agreements, such as the receipt by the underwriters of
officer's certificates and legal opinions. The underwriters reserve the right to
withdraw, cancel or modify offers to the public and to reject orders in whole or
in part.

Merrill Lynch will be facilitating Internet distribution for this offering
to certain of its Internet subscription customers. Merrill Lynch intends to
allocate a limited number of shares for sale to its online brokerage customers.
An electronic prospectus is available on the Internet Web site maintained by
Merrill Lynch.

Other than the prospectus in electronic format, the information on the Web
sites is not part of this prospectus.

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<PAGE> 75

COMMISSIONS AND DISCOUNTS

The U.S. representatives have advised us that the U.S. underwriters propose
initially to offer the shares to the public at the initial public offering price
on the cover page of this prospectus and to dealers at that price less a
concession not in excess of $ per share. The U.S. underwriters may allow,
and the dealers may reallow, a discount not in excess of $ per share to
other dealers. After the initial public offering, the public offering price,
concession and discount may be changed.

The following table shows the public offering price, underwriting discount
and proceeds before our expenses. The information assumes either no exercise or
full exercise by the U.S. underwriters and the international managers of their
over-allotment options.

<TABLE>
<CAPTION>
PER SHARE WITHOUT OPTIONS WITH OPTIONS
--------- --------------- ------------
<S> <C> <C> <C>
Public offering price........................... $ $ $
Underwriting discount........................... $ $ $
Proceeds, before expenses, to Energy Partners... $ $ $
</TABLE>

The expenses of this offering, not including the underwriting discount, are
estimated at $1.2 million and are payable by us.

OVER-ALLOTMENT OPTIONS

We have granted an option to the U.S. underwriters to purchase up to
690,000 additional shares at the public offering price less the underwriting
discount. The U.S. underwriters may exercise this option for 30 days from the
date of this prospectus solely to cover any over-allotments. If the U.S.
underwriters exercise this option, each U.S. underwriter will be obligated,
subject to conditions contained in the purchase agreement, to purchase a number
of additional shares proportionate to that U.S. underwriter's initial amount
reflected in the above table.

We have also granted an option to the international managers, exercisable
for 30 days from the date of this prospectus, to purchase up to 172,500
additional shares to cover any over-allotments on terms similar to those granted
to the U.S. underwriters.

INTERSYNDICATE AGREEMENT

The U.S. underwriters and the international managers have entered into an
intersyndicate agreement that provides for the coordination of their activities.
Under the intersyndicate agreement, the U.S. underwriters and the international
managers may sell shares to each other for purposes of resale at the initial
public offering price, less an amount not greater than the selling concession.
Under the intersyndicate agreement, the U.S. underwriters and any dealer to whom
they sell shares will not offer to sell or sell shares to persons who are
non-U.S. or non-Canadian persons or to persons they believe intend to resell to
persons who are non-U.S. or non-Canadian persons, except in the case of
transactions under the intersyndicate agreement. Similarly, the international
managers and any dealer to whom they sell shares will not offer to sell or sell
shares to U.S. persons or Canadian persons or to persons they believe intend to
resell to U.S. or Canadian persons, except in the case of transactions under the
intersyndicate agreement.

RESERVED SHARES

At our request, the U.S. underwriters have reserved up to % of the
shares of common stock for sale at the initial public offering price to persons
who are directors, officers or employees, or who are otherwise associated with
us through a directed share program. The number of shares of common stock
available for sale to the general public will be reduced by the number of
directed shares purchased by participants in the program. Any directed shares
not purchased will be offered by the U.S. underwriters to the general public on
the same basis as all other shares of common stock offered. We have agreed to

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<PAGE> 76

indemnify the U.S. underwriters against certain liabilities and expenses,
including liabilities under the Securities Act, in connection with the sales of
the directed shares.

NO SALES OF SIMILAR SECURITIES

We, our officers and directors, Evercore and Energy Income Fund have
agreed, with exceptions, not to sell or transfer any common stock for 180 days
after the date of this prospectus without first obtaining the written consent of
Merrill Lynch. Specifically, we and these other individuals have agreed not to
directly or indirectly

- offer, pledge, sell or contract to sell any common stock,

- sell any option or contract to purchase any common stock,

- purchase any option or contract to sell any common stock,

- grant any option, right or warrant for the sale of any common stock,
other than in connection with the conversion of our preferred stock into
common stock and pursuant to our employee benefit plan or non-employee
director stock option plan,

- lend or otherwise dispose of or transfer any common stock,

- request or demand that we file a registration statement related to the
common stock, other than in connection with our employee benefit plan or
non-employee director stock option plan, or

- enter into any swap or other agreement that transfers, in whole or in
part, the economic consequence of ownership of any common stock whether
any such swap or transaction is to be settled by delivery of shares or
other securities, in cash or otherwise.

This lockup provision applies to common stock and to securities convertible
into or exchangeable or exercisable for or repayable with common stock. It also
applies to common stock owned now or acquired later by the person executing the
agreement or for which the person executing the agreement later acquires the
power of disposition.

LISTING

We expect the shares to be approved for listing on the New York Stock
Exchange under the symbol "EPL." In order to meet the requirements for listing
on that exchange, the U.S. underwriters and the international managers have
undertaken to sell a minimum number of shares to a minimum number of beneficial
owners as required by that exchange.

Before this offering, there has been no public market for our common stock.
The initial public offering price will be determined through negotiations among
us and the U.S. representatives and lead managers. In addition to prevailing
market conditions, the factors to be considered in determining the initial
public offering price are

- the valuation multiples of publicly traded companies that the U.S.
representatives and the lead managers believe to be comparable to us,

- our financial information,

- the history of, and the prospects for, our company and the industry in
which we compete,

- an assessment of our management, its past and present operations, and the
prospects for, and timing of, our future revenues,

- the present state of our development, and

- the above factors in relation to market values and various valuation
measures of other companies engaged in activities similar to ours.

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<PAGE> 77

An active trading market for the shares may not develop. It is also
possible that after the offering the shares will not trade in the public market
at or above the initial public offering price.

The underwriters do not expect to sell more than 5% of the shares in the
aggregate to accounts over which they exercise discretionary authority.

PRICE STABILIZATION, SHORT POSITIONS AND PENALTY BIDS

Until the distribution of the common shares is completed, the SEC rules may
limit underwriters and selling group members from bidding for or purchasing our
common shares. However, the U.S. underwriters may engage in transactions that
stabilize the price of the common shares, such as bids or purchases that peg,
fix or maintain that price.

The U.S. underwriters may purchase and sell the common shares in the open
market. These transactions may include short sales, stabilizing transactions and
purchases to cover positions created by short sales. Short sales involve the
sale by the U.S. underwriters of a greater number of shares than they are
required to purchase in the offering. "Covered" short sales are sales made in an
amount not greater than the underwriters' option to purchase additional shares
from the issuer in the offering. The U.S. underwriters may close out any covered
short position by either exercising their option to purchase additional shares
or purchasing shares in the open market. In determining the source of shares to
close out the covered short position, the U.S. underwriters will consider, among
other things, the price of shares available for purchase in the open market as
compared to the price at which they may purchase shares through the
over-allotment option. "Naked" short sales are any sales in excess of such
option. The U.S. underwriters must close out any naked short position by
purchasing shares in the open market. A naked short position is more likely to
be created if the U.S. underwriters are concerned that there may be downward
pressure on the price of the common shares in the open market after pricing that
could adversely affect investors who purchase in the offering. Stabilizing
transactions consist of various bids for or purchases of common shares made by
the U.S. underwriters in the open market prior to the completion of the
offering.

The U.S. underwriters may also impose a penalty bid. This occurs when a
particular underwriter repays to the other underwriters a portion of the
underwriting discount received by it because the U.S. underwriters have
repurchased shares sold by or for the account of such underwriter in stabilizing
or short covering transactions.

Similar to other purchase transactions, the U.S. underwriters' purchases to
cover the syndicate short sales may have the effect of raising or maintaining
the market price of the common shares or preventing or retarding a decline in
the market price of the common shares. As a result, the price of the common
shares may be higher than the price that might otherwise exist in the open
market.

Neither we nor any of the underwriters make 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 shares. In addition, neither
we nor any of the underwriters makes any representation that the U.S.
underwriters or the international managers will engage in these transactions or
that these transactions, once commenced, will not be discontinued without
notice.

OTHER RELATIONSHIPS

In November 1999, we closed the private placement to Evercore. UBS Warburg
LLC acted as our advisor for this private placement, for which it received a
customary cash fee for its services. In addition, William O. Hiltz, a managing
director of UBS Warburg LLC, owns 150,000 shares of our common stock.

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<PAGE> 78

LEGAL MATTERS

The validity of our common shares offered in this offering will be passed
upon for us by Cahill Gordon & Reindel, New York, New York. Baker Botts L.L.P.
will act as counsel for the underwriters. Baker Botts L.L.P. acted as counsel to
Evercore Capital Partners L.P. in connection with its investment of $60.0
million in the company in November 1999.

EXPERTS

Our financial statements as of December 31, 1998 and 1999 and the period
from January 29, 1998 (inception) to December 31, 1998 and the year ended
December 31, 1999 have been included herein and in the registration statement in
reliance upon the report of KPMG LLP, independent certified public accountants,
appearing elsewhere herein, and upon the authority of said firm as experts in
accounting and auditing.

The statements of revenues and direct operating expenses of the 30%
interest in the Bay Marchand 2 Field, South Timbalier Block 26 for the nine
months ended December 31, 1998 and the year ended December 31, 1999, which we
acquired, have been included herein and in the registration statement in
reliance upon the report of KPMG LLP, independent certified public accountants,
appearing elsewhere herein, and upon the authority of said firm as experts in
accounting and auditing.

The statements of revenues and direct operating expenses of Ocean Energy,
Inc.'s 98.5% interest in the East Bay Complex for the three years ended December
31, 1999, which we acquired, have been included herein and in the registration
statement in reliance upon the report of KPMG LLP, independent certified public
accountants, appearing elsewhere herein, and upon the authority of said firm as
experts in accounting and auditing.

The estimated reserve evaluations and related calculations of Netherland,
Sewell & Associates, Inc., independent petroleum engineering consultants,
included in this prospectus and the exhibits to the registration statement of
which this prospectus is a part have been included in reliance on the authority
of said firm as experts in petroleum engineering.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC under the Securities Act a registration
statement on Form S-1 with respect to the common stock offered hereby. This
prospectus, which constitutes part of the registration statement, does not
contain all the information set forth in the registration statement or the
exhibits and schedules which are part of the registration statement, portions of
which are omitted as permitted by the rules and regulations of the SEC.
Statements made in this prospectus regarding the contents of any contract or
other document are summaries of the material terms of the contract or document.
With respect to each contract or document filed as an exhibit to the
registration statement, reference is made to the corresponding exhibit. For
further information pertaining to us and the common stock offered hereby,
reference is made to the registration statement, including the exhibits and
schedules thereto, copies of which may be inspected without charge at the public
reference facilities of the SEC at 450 Fifth Street, N.W., Washington, D.C.
20549 and at certain of the regional offices of the SEC located at Seven World
Trade Center, Suite 1300, New York, New York 10048, and Northwestern Atrium
Center, 500 West Madison Street, Chicago, Illinois 60611. Copies of all or any
portion of the registration statement may be obtained from the SEC at prescribed
rates. Information on the public reference facilities may be obtained by calling
the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that
contains reports, proxy and information statements and other information that is
filed through the SEC's EDGAR System. The web site can be accessed at
http://www.sec.gov.

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<PAGE> 79

GLOSSARY OF OIL AND NATURAL GAS TERMS

"3-D seismic" Geophysical data that depict the subsurface strata in three
dimensions. 3-D seismic typically provides a more detailed and accurate
interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

"Bbl" One stock tank barrel, or 42 U.S. gallons liquid volume, used in this
prospectus in reference to oil and other liquid hydrocarbons.

"Bcf" One billion cubic feet of natural gas.

"Boe" Barrels of oil equivalent, with six thousand cubic feet of natural
gas being equivalent to one barrel of oil.

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

"Mbbls" One thousand barrels of oil or other liquid hydrocarbons.

"Mboe" One thousand barrels of oil equivalent.

"Mcf" One thousand cubic feet of natural gas.

"Mmbls" Millions of barrels of oil or other liquid hydrocarbons.

"Mmboe" One million barrels of oil equivalent.

"Mmbtu" One million British Thermal Units.

"Mmcf" One million cubic feet of natural gas.

"plugging and abandonment" Refers to the sealing off of fluids in the
strata penetrated by a well so that the fluids from one stratum will not escape
into another or to the surface. Regulations of many states require plugging of
abandoned wells.

"payout" Generally refers to the recovery by the incurring party of its
costs of drilling, completing, equipping and operating a well before another
party's participation in the benefits of the well commences or is increased to a
new level.

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

"working interest" The interest in an oil and natural gas property
(normally a leasehold interest) that gives the owner the right to drill, produce
and conduct operations on the property and a share of production, subject to all
royalties, overriding royalties and other burdens and to all costs of
exploration, development and operations and all risks in connection therewith.

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ENERGY PARTNERS, LTD.

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<S> <C>
Energy Partners, Ltd.
Independent Auditors' Report.............................. F-2
Balance Sheets at December 31, 1998 and 1999.............. F-3
Statements of Operations for the period from January 29,
1998 (inception) to December 31, 1998 and the year
ended December 31, 1999................................ F-4
Statements of Changes in Stockholders' Equity for the
period from January 29, 1998 (inception) to December
31, 1998 and the year ended December 31, 1999.......... F-5
Statements of Cash Flows for the period from January 29,
1998 (inception) to December 31, 1998 and the year
ended December 31, 1999................................ F-6
Notes to Financial Statements............................. F-7
Consolidated Balance Sheet as of June 30, 2000
(unaudited)............................................ F-17
Consolidated Statements of Operations for the six months
ended June 30, 1999 and 2000 (unaudited)............... F-18
Consolidated Statements of Cash Flows for the six months
ended June 30, 1999 and 2000 (unaudited)............... F-19
Notes to Consolidated Financial Statements (unaudited).... F-20
South Timbalier 26
Independent Auditors' Report.............................. F-23
Statements of Revenues and Direct Operating Expenses for
the nine months ended December 31, 1998, the year ended
December 31, 1999 and the three months ended March 31,
2000 (unaudited)....................................... F-24
Notes to Financial Statements............................. F-25
East Bay
Independent Auditors' Report.............................. F-28
Statements of Revenues and Direct Operating Expenses for
the three years ended December 31, 1999 and the three
months ended March 31, 2000 (unaudited)................ F-29
Notes to Financial Statements............................. F-30
</TABLE>

F-1
<PAGE> 81

INDEPENDENT AUDITORS' REPORT

The Board of Directors
Energy Partners, Ltd.:

We have audited the accompanying balance sheets of Energy Partners, Ltd. as
of December 31, 1998 and 1999, and the related statements of operations, changes
in stockholders' equity, and cash flows for the period from January 29, 1998
(inception) to December 31, 1998 and the year ended December 31, 1999. 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 audits 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 Energy Partners, Ltd. as of
December 31, 1998 and 1999, and the results of its operations and its cash flows
for the period from January 29, 1998 (inception) to December 31, 1998 and the
year ended December 31, 1999, in conformity with generally accepted accounting
principles.

New Orleans, Louisiana
March 31, 2000, except as to
the third paragraph of
Note 9 and the
second paragraph of
Note 2(e), which are
as of April 20, 2000
and September 15, 2000, respectively.

F-2
<PAGE> 82

ENERGY PARTNERS, LTD.

BALANCE SHEETS
DECEMBER 31, 1998 AND 1999

<TABLE>
<CAPTION>
1998 1999
----------- -----------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 652,116 $22,282,376
Trade accounts receivable................................. 12,753,040 7,970,738
Prepaid expenses.......................................... 84,562 300,698
----------- -----------
Total current assets.............................. 13,489,718 30,553,812
Property and equipment, at cost under the successful efforts
method of accounting for oil and gas properties........... 27,081,424 42,241,227
Less accumulated depreciation, depletion and amortization... (1,236,709) (5,627,323)
----------- -----------
Net property and equipment........................ 25,844,715 36,613,904
Deferred income taxes....................................... 359,510 1,545,049
Deferred financing costs -- net of accumulated amortization
of $17,981 in 1998 and $108,130 in 1999................... 320,662 563,093
----------- -----------
$40,014,605 $69,275,858
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $16,641,052 $ 4,215,030
Accrued expenses.......................................... 3,894,695 1,623,489
Accrued interest.......................................... 106,667 169,850
----------- -----------
Total current liabilities......................... 20,642,414 6,008,369
Long-term debt.............................................. 20,000,000 10,150,000
Other....................................................... 66,667 457,386
----------- -----------
40,709,081 16,615,755
----------- -----------
Redeemable Preferred Stock, $1 par value, authorized
1,700,000 shares; issued and outstanding, 600,000 shares;
aggregate liquidation preference $60,800,000.............. -- 56,475,276
Stockholders' equity:
Common stock, par value $0.01 per share. Authorized
50,000,000 shares; issued and outstanding:
1998 -- 15,060,000 shares; 1999 -- 11,768,280
shares;................................................ 150,060 117,683
Additional paid-in capital................................ -- 32,377
Accumulated deficit....................................... (845,076) (3,965,233)
----------- -----------
Total stockholders' equity........................ (694,476) (3,815,173)
----------- -----------
$40,014,605 $69,275,858
=========== ===========
</TABLE>

See accompanying notes to financial statements.

F-3
<PAGE> 83

ENERGY PARTNERS, LTD.

STATEMENTS OF OPERATIONS
PERIOD FROM JANUARY 29, 1998 (INCEPTION) TO DECEMBER 31, 1998
AND YEAR ENDED DECEMBER 31, 1999

<TABLE>
<CAPTION>
1998 1999
----------- -----------
<S> <C> <C>
Revenue:
Oil and gas............................................... $ 1,791,775 $ 8,484,253
Other..................................................... 174,330 1,025,150
----------- -----------
1,966,105 9,509,403
----------- -----------
Costs and expenses:
Lease operating........................................... 359,228 1,640,586
Exploration expenditures and dry hole costs............... -- 1,570,058
Depreciation, depletion and amortization.................. 1,303,376 4,524,723
General and administrative................................ 614,416 2,608,803
----------- -----------
Total costs and expenses.......................... 2,277,020 10,344,170
----------- -----------
Loss from operations........................................ (310,915) (834,767)
----------- -----------
Other income (expense):
Interest income........................................... 48,656 312,227
Interest expense.......................................... (801,767) (2,947,354)
----------- -----------
(753,111) (2,635,127)
----------- -----------
Loss before income taxes.......................... (1,064,026) (3,469,894)
Income tax benefit.......................................... 359,510 1,185,539
----------- -----------
Net loss.......................................... (704,516) (2,284,355)
Less dividends earned on preferred stock and accretion of
issuance costs............................................ -- (836,342)
----------- -----------
Net loss available to common stockholders......... $ (704,516) $(3,120,697)
=========== ===========
Basic loss per share........................................ $ (0.09) $ (0.22)
=========== ===========
Diluted loss per share...................................... $ (0.09) $ (0.22)
=========== ===========
Weighted average common shares used in computing loss per
share:
Basic.................................................. 7,426,849 14,246,727
=========== ===========
Diluted................................................ 7,426,849 14,246,727
=========== ===========
Pro forma loss per share (note 11):
Basic loss per share................................... $ (2.07)
===========
Diluted loss per share................................. $ (2.07)
===========
Weighted average common shares used in computing pro forma
loss per share:........................................... 23,461,682
===========
Basic..................................................
Diluted................................................ 23,461,682
===========
</TABLE>

See accompanying notes to financial statements.

F-4
<PAGE> 84

ENERGY PARTNERS, LTD.

STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
PERIOD FROM JANUARY 29, 1998 (INCEPTION) TO DECEMBER 31, 1998
AND YEAR ENDED DECEMBER 31, 1999

<TABLE>
<CAPTION>
ADDITIONAL
COMMON COMMON PAID-IN ACCUMULATED
STOCK SHARES STOCK CAPITAL DEFICIT TOTAL
------------ -------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Balance at inception.............. -- $ -- $ -- $ -- $ --
Stock issued for cash............. 15,060,000 10,040 -- -- 10,040
Establishment of $0.01 par
value........................... -- 140,020 -- (140,020) --
Net loss.......................... -- -- -- (704,516) (704,516)
---------- -------- ------- ----------- -----------
Balance at December 31, 1998...... 15,060,000 150,060 -- 844,536 (694,476)
EIF Shares cancelled.............. (3,291,720) (32,377) 32,377 -- --
Dividends earned on Preferred
Stock........................... -- -- -- (800,000) (800,000)
Accretion of Preferred Stock
issuance costs.................. -- -- -- (36,342) (36,342)
Net loss.......................... -- -- -- (2,284,355) (2,284,355)
---------- -------- ------- ----------- -----------
Balance at December 31, 1999...... 11,768,280 $117,683 $32,377 $(3,965,233) $(3,815,173)
========== ======== ======= =========== ===========
</TABLE>

See accompanying notes to financial statements.

F-5
<PAGE> 85

ENERGY PARTNERS, LTD.

STATEMENTS OF CASH FLOWS
PERIOD FROM JANUARY 29, 1998 (INCEPTION) TO DECEMBER 31, 1998
AND YEAR ENDED DECEMBER 31, 1999

<TABLE>
<CAPTION>
1998 1999
------------ ------------
<S> <C> <C>
Cash flows from operating activities:
Net loss.................................................. $ (704,516) $ (2,284,355)
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization............... 1,303,376 4,524,723
Deferred income taxes.................................. (359,510) (1,185,539)
Exploration expenditures and dry hole costs............ -- 1,570,058
Amortization of deferred financing costs............... -- 90,149
Changes in operating assets and liabilities:
Accounts receivable.................................. (12,753,040) 4,782,302
Prepaids............................................. (84,562) (216,136)
Accounts payable and accrued expenses................ 20,535,747 (12,196,134)
Accrued interest..................................... 106,667 63,183
Other liabilities.................................... -- 257,395
------------ ------------
Net cash provided by (used in) operating
activities...................................... 8,044,162 (4,594,354)
------------ ------------
Cash flows used in investing activities
Property acquisitions..................................... (9,045,000) (1,410,000)
Exploration and development expenditures.................. (18,036,424) (17,822,730)
------------ ------------
(27,081,424) (19,232,730)
------------ ------------
Cash flows from financing activities:
Deferred financing costs.................................. (320,662) (331,580)
Repayments of long-term debt.............................. -- (30,300,000)
Proceeds from long-term debt.............................. 20,000,000 20,450,000
Proceeds from issuance of common stock.................... 10,040 --
Preferred Stock issuance costs............................ -- (4,361,076)
Proceeds from issuance of Preferred Stock................. -- 60,000,000
------------ ------------
Net cash provided by financing activities......... 19,689,378 45,457,344
------------ ------------
Net increase in cash and cash equivalents......... 652,116 21,630,260
Cash and cash equivalents at beginning of period............ -- 652,116
------------ ------------
Cash and cash equivalents at end of period.................. $ 652,116 $ 22,282,376
============ ============
Supplemental cash flow information:
Interest paid, net of amounts capitalized................. $ 982,856 $ 3,191,515
============ ============
Income taxes paid......................................... $ -- $ --
============ ============
Supplemental disclosures of non-cash equity information:
Dividends earned on Preferred Stock....................... $ -- $ 800,000
============ ============
</TABLE>

See accompanying notes to financial statements.

F-6
<PAGE> 86

ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1999
(1) ORGANIZATION

Energy Partners, Ltd. (the Company) was incorporated on January 29, 1998
and is an independent oil and natural gas exploration and production company
concentrated in the shallow to moderate depth waters in the central region of
the Gulf of Mexico Shelf; therefore, operations are directly affected by
fluctuating economic conditions of the domestic oil and natural gas industry.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Property and Equipment

The Company uses the successful efforts method of accounting for oil and
gas producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves, and
to drill and equip development wells are capitalized. Costs to drill exploratory
wells that do not find proved reserves, and geological and geophysical costs are
expensed.

Unproved oil and gas properties are periodically assessed on a
property-by-property basis, and a loss is recognized to the extent, if any, that
the cost of the property has been impaired. Capitalized costs of producing oil
and gas properties are depreciated and depleted by the units-of-production
method.

The Company assesses the impairment of capitalized costs of proved oil and
gas properties on a field-by-field basis, utilizing its current estimate of
future revenues and operating expenses. In the event net undiscounted cash flow
is less than the carrying value, an impairment loss is recorded based on the
present value of expected future net cash flows over the economic lives of the
reserves.

The estimated costs of dismantling and abandoning offshore oil and gas
properties are provided currently using the unit-of-production method. Such
provision is included in depletion, depreciation and amortization in the
accompanying statements of operations. As of December 31, 1999, such costs are
expected to be approximately $1.6 million. To date, $0.2 million has been
accrued and is included in other liabilities in the accompanying balance sheets.

On the sale or retirement of a complete unit of a proved property, the cost
and related accumulated depletion, depreciation and amortization are eliminated
from the property accounts, and the resulting gain or loss is recognized.

(b) Income Taxes

The Company accounts for income taxes under the asset and liability method
which requires that deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in the tax rates is
recognized in income in the period that includes the enactment date.

The Company earned a management fee for its service as the operator of
South Timbalier 26 in which it holds a 20% working interest, which is revenue
when the services are performed. Management fee revenue was $146,651 and
$766,075 in 1998 and 1999, respectively.

(d) Deferred Financing Costs

Costs incurred to obtain financing were deferred and are being amortized as
additional interest expense over the maturity period of the related debt.

F-7
<PAGE> 87
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

(e) Earnings Per Share

Basic earnings per share is computed by dividing income available to common
stockholders by the weighted average number of common shares outstanding during
the period. Diluted earnings per share is computed in the same manner as basic
earnings per share except that the denominator is increased to include the
number of additional common shares that could have been outstanding assuming the
exercise of convertible preferred stock shares, the warrant and escrow shares
and the potential shares that would have a dilutive effect on earnings per
share.

On July 12, 2000 the Board of Directors approved a fifteen hundred-for-one
stock split on the Company's common stock to be effected by the distribution of
fifteen hundred shares for each share outstanding. On September 15, 2000, the
Company increased the number of authorized common shares from 20,000 to
50,000,000 and established a par value of $0.01 per share. All shares
outstanding, per share amounts and par value have been restated to reflect the
stock split and the establishment of a par value.

The effect of the preferred dividends and accretion of issuance costs on
arriving at the loss available to common stockholders was none in 1998 and
$836,342 in 1999. The number of dilutive convertible preferred stock shares, the
warrant and escrow shares used in computing diluted earnings per share were none
as these securities were anti-dilutive in 1999.

(f) Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities 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.

(g) Revenue Recognition

The Company uses the entitlement method for recording natural gas sales
revenues. Under this method of accounting, revenue is recorded based on the
Company's net working interest in field production. Deliveries of natural gas in
excess of the Company's working interest are recorded as liabilities and
under-deliveries are recorded as receivables. These amounts are not material at
December 31, 1998 and 1999.

(h) Statements of Cash Flows

For purposes of the statements of cash flows, highly-liquid investments
with maturities of three months or less are considered cash equivalents. In 1998
and 1999, interest-bearing cash equivalents were approximately $0.5 million and
$23.2 million, respectively. Exploration expenditures incurred are excluded from
operating cash flows and included in investing activities.

(i) New Accounting Pronouncements

In June of 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities". Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains or losses) depends on
the intended use of the derivative and resulting designation. If certain
conditions are met, a derivative may be specifically designated as a "fair value
hedge," "cash flow hedge," or a hedge of the foreign currency exposure of a net
investment in a foreign operation. Statement 133 amends and supersedes a number
of existing Statements of Financial Accounting Standards, and nullifies or
modifies the consensus reached in a number of issues addressed by the Emerging
Issues Task Force. Statement 133, as amended, is effective
F-8
<PAGE> 88
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

for all fiscal quarters of fiscal years beginning after June 15, 2000. The
Company is assessing the impact of adoption of Statement 133, and at the present
time, has not quantified the effect of adoption or the continuing impact of such
adoption.

(3) PROPERTY AND EQUIPMENT

The following is a summary of property and equipment at December 31, 1998
and 1999:

<TABLE>
<CAPTION>
1998 1999
----------- -----------
<S> <C> <C>
Proved oil and gas properties.............................. $26,575,870 $41,466,815
Furniture and fixtures..................................... 505,554 774,412
----------- -----------
27,081,424 42,241,227
Less accumulated depreciation, depletion and
amortization............................................. (1,236,709) (5,627,323)
----------- -----------
Net property and equipment....................... $25,844,715 $36,613,904
=========== ===========
</TABLE>

The Company capitalizes interest on expenditures for significant
exploration and development projects while activities are in progress to bring
the assets to their intended use. Amounts capitalized were $287,754 and $307,344
in 1998 and 1999, respectively.

All oil and gas properties are collateral for long-term debt.

(4) REDEEMABLE PREFERRED STOCK

In 1999, the Company authorized 1,700,000 shares of preferred stock
(Preferred Stock) having a par value of $1.00 per share, of which 1,550,000
shares are designated as Series A and Series B Redeemable Cumulative Convertible
Preferred Stock and Series C Redeemable Cumulative Preferred Stock. In November
1999, the Company entered into a stock purchase agreement whereby 600,000 shares
of Series A and B Preferred Stock were sold for $60.0 million. At the time of
the transaction, these shares were convertible into the equivalent of 53.1% of
the voting common stock. At December 31, 1999, the Company had Preferred Stock
authorized, issued and outstanding as follows:

<TABLE>
<CAPTION>
AUTHORIZED ISSUED OUTSTANDING
---------- ------- -----------
<S> <C> <C> <C>
Series A............................................. 500,000 500,000 500,000
Series B............................................. 150,000 100,000 100,000
Series C............................................. 900,000 -- --
Undesignated......................................... 150,000 -- --
</TABLE>

The Preferred Stock earns cumulative dividends of 10% annually on the
liquidation value of the Series A and B Preferred Stock plus dividends in
arrears. The dividends on the Series A Preferred Stock are payable in additional
fully paid and non-assessable shares of Series C Preferred Stock, the dividends
on the Series B Preferred Stock are payable in additional fully paid and
non-assessable shares of Series B Preferred Stock and the dividends on the
Series C Preferred Stock are payable in cash. All accrued dividends are recorded
as an increase to the carrying value of the Preferred Stock and must be paid
prior to the payment of any dividends on common stock. At December 31, 1999,
there was $800,000 ($0.06 per share) of Preferred Stock dividends in arrears, of
which approximately $133,333 is Series B Preferred Stock recorded at fair value.

On November 17, 2009, the Company will be required to redeem all
outstanding shares of (a) Series A and B Preferred Stock at a redemption price
of the greater of (i) $100 per share plus accrued dividends in cash or (ii) at
the fair market price of the number of shares of common stock into which the
shares of Series A and B Preferred Stock are convertible on that date pursuant
to the terms of

F-9
<PAGE> 89
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

the Series A and B Preferred Stock Certificates of Designations (Certificates of
Designations) and (b) Series C Preferred Stock at a redemption price of $100 per
share plus accrued dividends in cash.

Provided that full cumulative dividends on the Preferred Stock are declared
and paid to date, the holders of the Series A and B Preferred Stock may convert
them into the number of fully paid and non-assessable shares of common stock
based on a formula of dividing the liquidation value of the Preferred Stock by
the fair value of the common stock (approximately $6.50 at November 17, 1999),
pursuant to the Certificates of Designation. Also, provided such dividends are
declared and paid and upon the closing of a qualifying public offering, each
share of Series A and B Preferred Stock will automatically convert into the
number of shares of Common Stock on that date based on the formula discussed
above.

The Company may redeem all of the outstanding shares of Preferred Stock
after March 31, 2002. The total redemption value of the Preferred Stock
outstanding at December 31, 1999 is presented on the Company's balance sheet net
of issuance costs of approximately $4,325,000. These costs are being accreted
over the 10-year period to the mandatory redemption date.

In the event of any liquidation, dissolution or winding up of the affairs
of the Company, holders of the Preferred Stock will be paid before payment to
other stockholders. Holders of the Series A and B preferred stock will be paid
the greater of (i) $100 per share plus accrued dividends or (ii) the fair market
price of the number of shares of common stock into which the shares of Series A
and B Preferred Stock are convertible on that date pursuant to the Certificates
of Designation. The holders of the Series C preferred stock will be paid $100
per share plus accrued dividends.

(5) LONG-TERM DEBT

In June 1999, the Company entered into a reducing revolving line of credit
of $50.0 million with a bank. At December 31, 1999, the reducing revolving
credit agreement had a borrowing base of $20.0 million and an expiration date of
June 1, 2002. The agreement provides for monthly principal payments to the
extent that the loan balance exceeds the borrowing base. Interest is at the
banks prime rate plus 1/2% (9% at December 31, 1999). The amount outstanding
under this agreement was $150,000 at December 31, 1999. The fair value of
amounts outstanding under this financing agreement approximate book value at
December 31, 1999.

On April 15, 1998, the Company entered into a $20.0 million financing
agreement with Energy Income Fund, L.P.(EIF). The borrowing base under the
original agreement was $10.0 million. EIF also purchased 7,515,000 shares of the
Company's common stock in June of 1998, prior to the commencement of significant
operations, for $5,010 or approximately $.0007 per common share. The financing
agreement was amended on June 19, 1998 to increase the borrowing base to $20.0
million. As of December 31, 1998 $20.0 million was outstanding under this
financing agreement.

On February 10, 1999, the financing agreement was further amended to
increase the facility to $25.0 million. On November 17, 1999, in conjunction
with the preferred stock transaction described in Note 4, the financing
agreement was reduced to $10.0 million. The Company used $15.0 million of the
proceeds from the Preferred Stock transaction to pay down the debt due to EIF.
Interest accrues at 13% through September 30, 2000, 14% through December 31,
2000 and 15% thereafter. The terms of the financing agreement, as amended on
March 31, 2000, require repayment by July 1, 2001. Amounts outstanding under
this agreement are subordinated to the bank debt. The fair value of amounts
outstanding under this financing agreement approximate book value at December
31, 1999.

On November 17, 1999, EIF returned 3,291,720 shares of common stock as
required by the preferred stock transaction discussed in Note 4. The amount
originally paid by EIF for these shares of $2,194 was reclassified to additional
paid-in capital in 1999.

F-10
<PAGE> 90
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

Also on November 17, 1999, the Company issued a warrant to EIF to purchase
928,050 shares of common stock as required by the Preferred Stock transaction
discussed in Note 4. The warrant is exercisable at approximately $6.50 per share
or through cashless exercise, subject to adjustment as specified in the
agreement, in whole or in part at any time for a period of 60 days after the
first to occur of (i) a qualifying public offering or (ii) December 31, 2001,
subject to the Company meeting specified reserve replacement targets. The
warrant was assigned no value at the date of issuance.

(6) INCOME TAXES

Components of income tax benefit for the periods ended December 31, 1998
and 1999 are as follows:

<TABLE>
<CAPTION>
CURRENT DEFERRED TOTAL
------- ----------- -----------
<S> <C> <C> <C>
1998:
Federal......................................... $-- $ (359,510) $ (359,510)
State........................................... -- -- --
--- ----------- -----------
$-- $ (359,510) $ (359,510)
=== =========== ===========
1999:
Federal......................................... $-- $(1,185,539) $(1,185,539)
State........................................... -- -- --
--- ----------- -----------
$-- $(1,185,539) $(1,185,539)
=== =========== ===========
</TABLE>

The effective rates of income tax expense are (33.8%) and (34.2%) for the
periods ended December 31, 1998 and 1999, respectively. The reasons for the
differences between the effective tax rates and the "expected" corporate federal
income tax rate of 34% is as follows:

<TABLE>
<CAPTION>
PERCENTAGE OF
PRETAX EARNINGS
---------------
1998 1999
----- -----
<S> <C> <C>
Expected tax rate........................................... (34.0)% (34.0)%
Other....................................................... 0.2 (0.2)
----- -----
(33.8)% (34.2)%
===== =====
</TABLE>

The tax effects of temporary differences that give rise to significant
portions of the net deferred tax asset at December 31, 1998 and 1999 are
presented below:

<TABLE>
<CAPTION>
1998 1999
-------- ----------
<S> <C> <C>
Deferred tax asset -- federal net operating loss
carryforwards............................................. $430,281 $7,528,716
Deferred tax liabilities -- property, plant and equipment,
principally due to differences in depreciation and
capitalized interest...................................... 70,771 5,983,667
-------- ----------
Net deferred tax asset................................. $359,510 $1,545,049
======== ==========
</TABLE>

At December 31, 1999, the Company had a net operating loss carryforward of
approximately $22,000,000, which is available to reduce future federal taxable
income through 2019. Although realization is not assured, management believes it
is more likely than not that all of the deferred tax assets will be realized
through future earnings and tax planning strategies. As a result, no valuation
allowance has been provided.

F-11
<PAGE> 91
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

(7) COMMITMENTS AND CONTINGENCIES

The Company has an operating lease for office space which expires in 2008.

Future minimum lease commitments as of December 31, 1999 under this
operating lease are as follows:

<TABLE>
<S> <C>
2000........................................................ $ 404,629
2001........................................................ 680,918
2002........................................................ 680,918
2003........................................................ 680,918
2004........................................................ 723,469
Thereafter.................................................. 3,021,549
----------
$6,192,401
==========
</TABLE>

Rent expense for the periods ended December 31, 1998 and 1999 was
approximately and $100,000 and $388,500, respectively.

From time to time, the Company is involved in litigation arising out of
operations in the normal course of business. In management's opinion, the
Company is not involved in any litigation, the outcome of which would have a
material effect on the financial position, results of operations or liquidity of
the Company.

(8) ESCROW SHARES

In November 1999, as a requirement to complete the Preferred Stock
transaction discussed in Note 4, management and director stockholders placed in
escrow 3,304,830 shares of common stock. These common shares were originally
issued in early 1998, as part of the initial capitalization of the Company, for
cash prior to the commencement of any significant operations by the Company.
These shares may not be voted by the management and director stockholders and
all or a portion will be released from escrow only upon the attainment of
specified reserve replacement targets or upon completion of a qualifying public
offering. At such time as the qualifying public offering is completed or that it
becomes probable the reserve replacement targets are met, compensation expense
to the management stockholders equal to the fair value of the shares at that
time will be recorded by the Company. If the Company meets the reserve
replacement target by December 31, 2001 then all of the shares will be released.
Any shares not released as a result of not meeting the reserve replacement
target, will be cancelled. If the shares are released as a result of a
qualifying public offering, only 77% or approximately 2,545,500 shares will be
released (2,530,007 to management stockholders). The remaining shares will be
cancelled. Compensation expense for the shares released to the management
stockholders if the maximum reserve replacement target is met and if a
qualifying public offering is completed is estimated to be $59.0 million and
$45.5 million, respectively. Estimated compensation expense was calculated using
$18.00, the estimated offering price for the Company's common stock.

An additional 139,500 shares of common stock are available for grant to
employees and if granted, will vest at the time of the qualifying public
offering.

(9) SUBSEQUENT EVENT

On March 31, 2000, the Company purchased an 80% working interest in South
Timbalier 26 from Unocal for approximately $44.9 million, which included $1.25
million for pipeline assets acquired by a wholly owned subsidiary of the
Company, EPL Pipeline L.L.C. Additionally, on March 31, 2000 the

F-12
<PAGE> 92
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

Company purchased an average 98.5% working interest in East Bay Field (East Bay)
from Ocean Energy, Inc. for approximately $72.6 million.

In order to finance the acquisitions, the Company entered into a reducing
revolving line of credit with the bank. The agreement provides for a $90.0
million reducing revolving line of credit and a $25.0 million reducing bridge
financing (together, bank facility). Beginning June 1, 2000, the borrowing base
reductions are $1.6 million monthly on the $90.0 million portion and $0.4
million monthly on the $25.0 million portion. The $25.0 million reducing bridge
financing terminates on March 30, 2001. The amount outstanding under the bank
facility was $108.0 million at March 31, 2000.

On April 20, 2000, the Company completed the sale of 50% of its working
interest in South Timbalier 26. Proceeds from the sale were used to reduce the
borrowings under the bank facility to approximately $71.8 million. As a result
of this reduction, the borrowing base reduction on the $90.0 million portion was
adjusted to $1.4 million.

In the purchases and the sale of the properties, the respective buyers have
the right to audit the closing statements. We do not expect any material
adjustments as a result of these audits.

(10) RELATED PARTY

The Company's President and Chief Executive Officer serves on the board of
directors of a company that provides contract operations and other production
services to the Company. The Company incurred expenses from this service
provider of $3.2 million and $4.7 million in 1998 and 1999, respectively. Loss
of this service provider would not have a material adverse effect on the
operations of the Company.

On January 21, 1999, the Board of Directors approved the establishment of a
3% overriding royalty fund for executive stockholders. The royalty was to be
paid based on revenue on all existing properties to the extent that funds were
available from net operating income. A formal plan was not developed, however at
the time of the Preferred Stock transaction described in Note 4 the Board of
Directors approved a payment to the executive stockholders approximating the 3%
override as if the plan had been formalized. The charge of approximately
$490,000 has been recorded in the 1999 statement of operations. The Company no
longer has any obligation for the overriding royalty fund.

(11) PRO FORMA AMOUNTS

The pro forma share and per share amounts on the statements of operations
assumes that the Preferred Stock discussed in Note 4 converted and the 2,545,500
of escrow shares discussed in Note 8 were released on January 1, 1999.

(12) SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED

Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures. Proved reserves
are estimated quantities of natural gas, crude oil and condensate that
geological and

F-13
<PAGE> 93
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

engineering data demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.

Proved developed reserves are proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.

On March 31, 2000 with an effective date of January 1, 2000, the Company
acquired an average 98.5% interest in the East Bay Complex and an additional net
30% interest in South Timbalier Block 26. These acquisitions which are not
reflected in the following reserve data caused a material change in the
estimates of proved or proved developed reserves.

The following table sets forth the Company's net proved reserves, including
the changes therein, and proved developed reserves.

<TABLE>
<CAPTION>
CRUDE OIL NATURAL GAS
(MBBLS) (MMCF)
--------- -----------
<S> <C> <C>
Proved developed and undeveloped reserves:
January 29, 1998............................................ -- --
Purchase of reserves in place............................. 1,995 5,335
Extensions, discoveries and other additions............... 962 7,437
Production................................................ (96) (238)
----- ------
2,861 12,534
December 31, 1998:
Extensions, discoveries and other additions............... 1,079 267
Purchase of reserves in place............................. 268 782
Production................................................ (384) (831)
----- ------
December 31, 1999........................................... 3,824 12,752
===== ======
Proved developed reserves:
December 31, 1998......................................... 2,467 10,859
December 31, 1999......................................... 2,715 7,631
</TABLE>

Capitalized costs for oil and gas producing activities consist of the
following:

<TABLE>
<CAPTION>
1998 1999
----------- -----------
<S> <C> <C>
Proved properties......................................... $26,575,870 $41,466,815
Unproved properties....................................... -- --
Accumulated depreciation, depletion and amortization...... (1,169,443) (5,362,024)
----------- -----------
Net capitalized costs........................... $25,406,427 $36,104,791
=========== ===========
</TABLE>

Costs incurred for oil and gas property acquisition, exploration and
development activities for the period ended December 31, 1998 and the year ended
December 31, 1999 are as follows:

<TABLE>
<CAPTION>
1998 1999
----------- -----------
<S> <C> <C>
Oil and gas property acquisition........................... $ 9,045,000 $ 1,410,000
Exploration................................................ 249,000 1,507,500
Development................................................ 17,282,000 15,604,200
----------- -----------
Total costs incurred............................. $26,576,000 $18,521,700
=========== ===========
</TABLE>

F-14
<PAGE> 94
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO RESERVES

The following information has been developed utilizing procedures
prescribed by Statement of Financial Accounting Standards No. 69 "Disclosures
about Oil and Gas Producing Activities" (SFAS No. 69). It may be useful for
certain comparative purposes, but should not be solely relied upon in evaluating
the Company or its performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into
account in reviewing the following information: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and gas revenues; and (4)
future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by
applying period end oil and gas prices adjusted for field and determinable
escalations to the estimated future production of period-end proved reserves.
Future cash inflows were reduced by estimated future development, abandonment
and production costs based on period-end costs in order to arrive at net cash
flow before tax. Future income tax expense has been computed by applying
period-end statutory tax rates to aggregate future net cash flows, reduced by
the tax basis of the properties involved and tax carryforwards. Use of a 10%
discount rate is required by SFAS No. 69.

Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.

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

<TABLE>
<CAPTION>
1998 1999
-------- --------
<S> <C> <C>
Future cash inflows......................................... $ 61,483 $125,038
Future production costs................................... (9,900) (29,036)
Future development and abandonment costs.................. (10,532) (19,003)
Future income tax expense................................. (5,434) (12,906)
-------- --------
Future net cash flows after income taxes.................... 35,617 64,093
10% annual discount for estimated timing of cash flows...... (10,728) (16,916)
-------- --------
Standardized measure of discounted future net cash flows.... $ 24,889 $ 47,177
======== ========
</TABLE>

F-15
<PAGE> 95
ENERGY PARTNERS, LTD.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves for the period ended
December 31, 1998 and year ended December 31, 1999 is as follows (in thousands):

<TABLE>
<CAPTION>
1998 1999
-------- --------
<S> <C> <C>
Beginning of the period..................................... $ -- $ 24,889
Sales and transfers of oil and gas produced, net of
production costs.......................................... (1,433) (6,843)
Net changes in prices and production costs.................. (18,469) 13,232
Extensions, discoveries and improved recoveries, net of
future production costs................................... 23,649 18,130
Development costs incurred during the period................ 17,531 18,141
Purchase of reserves in place............................... 9,045 1,410
Change in estimated future development costs................ -- (14,352)
Accretion of discount....................................... -- 42
Net change in income taxes.................................. (5,434) (7,472)
-------- --------
Net increase................................................ 24,889 22,288
-------- --------
End of period............................................... $ 24,889 $ 47,177
======== ========
</TABLE>

The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 1999 was based on
period end prices realized which averaged approximately $2.42 per mcf for
natural gas and approximately $24.64 per barrel for crude oil.

F-16
<PAGE> 96

ENERGY PARTNERS, LTD.

CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
AS OF JUNE 30, PRO FORMA
2000 JUNE 30, 2000
(UNAUDITED) (UNAUDITED)
-------------- -------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 6,663,676 $ 3,512,637
Trade accounts receivable................................. 12,744,325 12,744,325
Other receivables......................................... 6,421,591 6,421,591
Prepaid expenses.......................................... 1,395,355 1,395,355
------------ ------------
Total current assets................................... 27,224,947 24,073,908
Property and equipment, at cost under the successful efforts
method of accounting for oil and gas properties........... 144,711,330 144,711,330
Less accumulated depreciation, depletion and amortization... (11,597,040) (11,597,040)
------------ ------------
Net property and equipment............................. 133,114,290 133,114,290
Other assets................................................ 500,000 500,000
Deferred financing costs -- net of accumulated amortization
of $362,766............................................... 3,002,012 3,002,012
------------ ------------
$163,841,249 $160,690,210
============ ============

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 5,483,819 $ 5,483,819
Accrued expenses.......................................... 16,108,348 16,108,348
Current maturities of long-term debt...................... 15,000,000 15,000,000
------------ ------------
Total current liabilities.............................. 36,592,167 36,592,167
Long-term debt.............................................. 60,000,000 60,000,000
Deferred income taxes....................................... 3,077,848 3,077,848
Other....................................................... 2,645,039 2,645,039
------------ ------------
102,315,054 102,315,054
------------ ------------
Redeemable Convertible Preferred Stock, $1 par value,
authorized 1,700,000 shares; issued and outstanding,
600,000 shares aggregate liquidation preference
$64,814,529............................................... 60,663,088 --
Stockholders' equity:
Common stock, par value $0.01 per share. Authorized
50,000,000 shares; issued and outstanding 11,798,280
shares................................................. 117,983 211,281
Additional paid-in capital................................ 422,077 57,840,828
Retained earnings......................................... 323,047 323,047
------------ ------------
Total stockholders' equity............................. 863,057 58,375,156
------------ ------------
$163,841,249 $160,690,210
============ ============
</TABLE>

See accompanying notes to financial statements.

F-17
<PAGE> 97

ENERGY PARTNERS, LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS
SIX-MONTHS ENDED JUNE 30, 1999 AND 2000
(UNAUDITED)

<TABLE>
<CAPTION>
1999 2000
----------- -----------
<S> <C> <C>
Revenue:
Oil and gas............................................... $ 3,214,186 $30,009,170
Other..................................................... 565,953 347,083
----------- -----------
3,780,139 30,356,253
----------- -----------
Costs and expenses:
Lease operating........................................... 622,701 7,992,163
Exploration expenditures.................................. 461 824,195
Depreciation, depletion and amortization.................. 1,935,819 8,286,493
General and administrative................................ 1,098,437 5,161,710
----------- -----------
Total costs and expenses.......................... 3,657,418 22,264,561
----------- -----------
Income from operations...................................... 122,721 8,091,692
----------- -----------
Other income (expense):
Interest income........................................... 84,734 327,510
Interest expense.......................................... (1,301,049) (3,056,860)
Gain on sale of oil and gas assets........................ -- 7,781,448
----------- -----------
(1,216,315) 5,052,098
----------- -----------
Income (loss) before income taxes...................... (1,093,594) 13,143,790
Income taxes................................................ 374,961 (4,622,927)
----------- -----------
Net income (loss)...................................... (718,633) 8,520,863
Less dividends earned on preferred stock.................... -- (4,232,583)
----------- -----------
Net income (loss) available to common shareholders..... $ (718,633) $ 4,288,280
=========== ===========
Basic income (loss) per share............................... $ (0.05) $ 0.49
=========== ===========
Diluted income (loss) per share............................. $ (0.05) $ 0.47
=========== ===========
Weighted average common shares used in computing income
(loss) per share:
Basic..................................................... 15,060,000 8,747,000
=========== ===========
Diluted................................................... 15,060,000 18,076,839
=========== ===========
Pro forma income per share (note 6):
Basic income per share.................................... $ 0.41
===========
Diluted income per share.................................. $ 0.41
===========
Weighted average common shares used in computing pro forma
income per share:
Basic..................................................... 20,622,339
===========
Diluted................................................... 20,622,339
===========
</TABLE>

See accompanying notes to financial statements.

F-18
<PAGE> 98

ENERGY PARTNERS, LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS
SIX-MONTHS ENDED JUNE 30, 1999 AND 2000
(UNAUDITED)

<TABLE>
<CAPTION>
1999 2000
------------ -------------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss)......................................... $ (718,633) $ 8,520,863
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization............. 1,935,819 8,286,493
Gain on sale of oil and gas assets................... -- (7,781,448)
Stock-based compensation -- expense.................. -- 832,188
Deferred income taxes................................ (374,961) 4,395,333
Exploration expenditures............................. 461 824,195
Amortization of deferred financing costs............. 16,515 254,636
Changes in operating assets and liabilities:
Receivables....................................... 7,499,298 (13,033,453)
Prepaid expenses.................................. 14,254 (1,094,656)
Other assets...................................... -- (500,000)
Accounts payable and accrued expenses............. (3,372,463) 6,262,410
Other liabilities................................. 165,082 146,974
------------ -------------
Net cash provided by operating activities......... 5,165,372 7,113,535
------------ -------------
Cash flows used in investing activities:
Property acquisitions..................................... -- (117,390,382)
Exploration and development expenditures.................. (10,001,326) (4,063,827)
Proceeds from sale of oil and gas assets.................. -- 36,609,740
------------ -------------
Cash used in investing activities................. (10,001,326) (84,844,469)
------------ -------------
Cash flows from financing activities:
Deferred financing costs.................................. (139,144) (2,737,766)
Proceeds from long-term debt.............................. 8,000,000 108,000,000
Repayment of long-term debt............................... -- (43,150,000)
------------ -------------
Net cash provided by financing activities......... 7,860,856 62,112,234
------------ -------------
Net increase (decrease) in cash and cash
equivalents..................................... 3,024,902 (15,618,700)
Cash and cash equivalents at beginning of period............ 652,116 22,282,376
------------ -------------
Cash and cash equivalents at end of period.................. $ 3,677,018 $ 6,663,676
============ =============
Supplemental disclosure of non-cash equity information:
Dividends earned on Preferred Stock....................... -- 4,014,529
============ =============
</TABLE>

See accompanying notes to financial statements.

F-19
<PAGE> 99

ENERGY PARTNERS, LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED JUNE 30, 1999 AND 2000
(UNAUDITED)

(1) BASIS OF PRESENTATION

The consolidated financial statements include the accounts of Energy
Partners, Ltd. (EPL) and EPL Pipeline L.L.C. (a wholly-owned subsidiary of EPL).
EPL Pipeline L.L.C. was formed on February 3, 2000 to own and operate pipeline
assets acquired from Unocal Corporation (Unocal) on March 31, 2000.

Certain information and footnote disclosures normally in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to rules and regulations of the
Securities and Exchange Commission; however, management believes the disclosures
which are made are adequate to make the information presented not misleading.
These financial statements and footnotes should be read in conjunction with the
financial statements and notes thereto included in the Company's financial
statements for the year ended December 31, 1999.

The financial information as of June 30, 2000 and for the six months ended
June 30, 1999 and 2000, has not been audited. However, in the opinion of
management, all adjustments (which include only normal recurring adjustments)
necessary to present fairly the results of operations for the periods presented
have been included therein. The results of operations for the first six months
of the year are not necessarily indicative of the results of operations, which
might be expected for the entire year.

(2) ACQUISITIONS AND DISPOSITIONS

On March 31, 2000, the Company purchased an 80% working interest in South
Timbalier 26 from Unocal for approximately $44.9 million, which included $1.25
million for the pipeline assets discussed above. Additionally, on March 31, 2000
the Company purchased an average 98.5% working interest in East Bay Field (East
Bay) from Ocean Energy, Inc. for approximately $72.6 million. The entire
purchase price for both acquisitions was allocated to property and equipment.
The terms of the acquisitions did not contain any contingent consideration,
options or future commitments.

On April 20, 2000, the Company sold a 50% working interest in ST 26 for
approximately $36.6 million resulting in a gain of approximately $7.8 million.
The proceeds from this sale were used to reduce the borrowings under the
reducing revolving line of credit.

In the purchases and sale of the properties, the respective buyers have the
right to audit the closing statements. We do not expect any material adjustments
as a result of these audits.

(3) LONG-TERM DEBT

In order to finance the acquisitions discussed above, the Company amended
its reducing revolving line of credit with the bank. The agreement, as amended,
provides for a $90.0 million reducing revolving line of credit with interest at
LIBOR plus 3.0% and a $25.0 million reducing bridge financing with interest at
LIBOR plus 5.5%. As a result of the payment discussed above, beginning June 1,
2000, the borrowing base reductions are $1.4 million monthly on the $90.0
million portion and $0.4 million monthly on the $25.0 million portion. The
agreement provides for monthly principal payments to the extent that the loan
balance exceeds the borrowing base. The $25.0 million reducing bridge financing
terminates on March 30, 2001.

(4) EARNINGS PER SHARE

F-20
<PAGE> 100
ENERGY PARTNERS, LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

include the number of additional common shares that could have been outstanding
assuming the exercise of stock options, convertible preferred stock shares and
warrants and the potential shares that would have a dilutive effect on earnings
per share. The effect of the preferred stock dividends and accretion of issuance
costs on arriving at income available to common stockholders was none in 1999
and $4,232,583 in 2000. The number of dilutive convertible preferred stock
shares, the warrant and escrow shares and stock awards used in computing diluted
earnings per share were none in 1999 as these securities were antidilutive and
9,329,839 in 2000.

On July 12, 2000, the Board of Directors approved a fifteen hundred-for-one
stock split on the Company's common stock to be effected by the distribution of
fifteen hundred shares for each share outstanding. On September 15, 2000, the
Company increased the number of authorized common shares from 20,000 to
50,000,000 and established a par value of $0.01 per share. All shares
outstanding, per share amounts and par value have been restated to reflect the
stock split and the establishment of a par value.

(5) STOCK-BASED COMPENSATION

The Company uses the intrinsic value based method of accounting for
stock-based compensation as prescribed by Accounting Principles Board's Opinion
No. 25, "Accounting for Stock Issued to Employees."

In April 2000, an employee, pursuant to their employment agreement, was
granted 90,000 shares of restricted stock and stock options to purchase 375,000
shares of common stock. One-third of the restricted stock granted vested upon
the execution of the employment agreement and one-third will vest on the first
and second anniversary of the agreement. The stock options vest and are
exercisable at the prices as follows: 150,000 shares at $7.67 per share after
one year, 250,000 shares at $8.82 per share after two years and the remaining
shares at $10.14 after three years.

The grant date fair value of the restricted stock and options was $13.00,
the minimum price for a qualifying public offering of the Company's common
stock. The Company recognized compensation expense in 2000 of $832,188 related
to the restricted stock and stock option grants.

(6) HEDGING ACTIVITIES

Subsequent to June 30, 2000, the Company entered into derivative commodity
instruments to manage commodity price risks associated with future crude oil
production but does not use them for speculative purposes. The Company's
commodity price hedging program utilizes swap contracts. To qualify as a hedge,
these contracts must correlate to anticipated future production such that the
Company's exposure to the effects of commodity price changes is reduced. The
gains and losses related to these hedging transactions are recognized as
adjustments to the revenue recorded for the related production. The Company uses
the accrual method of accounting for derivative commodity instruments. At
inception, any contract premiums paid are recorded as prepaid expenses and, upon
settlement of the hedged production month, are included with the gains and
losses on the contracts in oil and gas revenues. As of June 30, 2000, the
Company had contracts maturing monthly through May 2001 related to the net sale
of 2,153,000 barrels of crude oil at an average price of $23.86 per barrel. The
effect to the Company to terminate these contracts at June 30, 2000 was
estimated to be a loss of $9.7 million.

F-21
<PAGE> 101
ENERGY PARTNERS, LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

specifically designated as a "fair value hedge," "cash flow hedge," or a hedge
of the foreign currency exposure of a net investment in a foreign operation.
Statement 133 amends and supersedes a number of existing Statements of Financial
Accounting Standards, and nullifies or modifies the consensus reached in a
number of issues addressed by the Emerging Issues Task Force. Statement 133, as
amended, is effective for all fiscal quarters of fiscal years beginning after
June 15, 2000. The Company is assessing the impact of adoption of Statement 133,
and at the present time, has not quantified the effect of adoption or the
continuing impact of such adoption.

(6) PRO FORMA AMOUNTS

The pro forma June 30, 2000 balance sheet reflects the conversion of the
Preferred Stock into 9,329,839 shares of common stock as a result of the
completion of a qualifying public offering. The conversion was effected using a
conversion formula of class A and B Preferred Stock, including accrued Class B
dividends convertible into common shares of 96,955 and payment of the Class C
dividends in cash.

The pro forma share and per share amounts on the statements of operations
assumes that the Preferred Stock discussed above converted and the 2,545,500 of
escrow shares with an expense of approximately $45.5 million were released on
January 1, 1999.

F-22
<PAGE> 102

INDEPENDENT AUDITORS' REPORT

The Board of Directors
Energy Partners, Ltd.:

We have audited the accompanying statements of revenues and direct
operating expenses of the 30% Interest in the Bay Marchand 2 Field, South
Timbalier Block 26 for the nine months ended December 31, 1998 and the year
ended December 31, 1999, acquired by Energy Partners, Ltd. These financial
statements are the responsibility of Energy Partners, Ltd.'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 audits to obtain
reasonable assurance about whether the statements of revenues and direct
operating expenses are free of material misstatement. An audit of a statement of
revenues and direct operating expenses includes examining, on a test basis,
evidence supporting the amounts and disclosures in that financial statement. An
audit of a statement of revenues and direct operating expenses 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 of the statements of revenues and direct operating
expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission and excludes material expenses, described in
Note 1 to the financial statements, that would not be comparable to those
resulting from the proposed future operations of the oil and gas property and is
not intended to be a complete presentation of revenue and expenses.

In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of the Interest acquired in the South Timbalier Block
26 Field as described in Note 1 for the nine months ended December 31, 1998 and
the year ended December 31, 1999, in conformity with generally accepted
accounting principles.

KPMG LLP

New Orleans, Louisiana
May 19, 2000

F-23
<PAGE> 103

30% INTEREST
SOUTH TIMBALIER BLOCK 26

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE NINE MONTHS ENDED DECEMBER 31, 1998, THE YEAR ENDED DECEMBER 31, 1999
AND THE THREE MONTHS ENDED MARCH 31, 2000

<TABLE>
<CAPTION>
2000
1998 1999 (UNAUDITED)
---------- ---------- -----------
<S> <C> <C> <C>
Revenues -- oil and gas sales............................ $2,349,417 $7,948,611 $3,186,203
Direct operating expenses................................ 952,034 1,747,901 736,057
---------- ---------- ----------
Excess of revenues over direct operating expenses........ $1,397,383 $6,200,710 $2,450,146
========== ========== ==========
</TABLE>

See accompanying notes to statements of revenues and direct operating expenses.

F-24
<PAGE> 104

30% INTEREST
SOUTH TIMBALIER BLOCK 26

NOTES TO FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct
operating expenses of Unocal Corporation (Unocal) 30% interest in the Bay
Marchand 2 Field, South Timbalier Block 26 (the Property) for the nine months
ended December 31, 1998 and the year ended December 31, 1999. Energy Partners,
Ltd. (the Company) acquired an 80% interest in the property from Unocal on March
31, 2000 for $43.6 million and subsequently sold 50% on April 20, 2000 for $36.4
million, therefore, the accompanying financial statements present the net 30%
acquired.

The accompanying statements of revenues and direct operating expenses of
the Property do not include general and administrative expenses, interest
expense, depreciation, depletion and amortization, or any provision for income
taxes since historical expenses of this nature incurred by Unocal are not
necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating
expenses are recognized on the entitlement method. Direct operating expenses are
recognized on the accrual basis and consist of monthly operator overhead costs
and other direct costs of operating the Property which were charged to the joint
account of working interest owners by the operator of the wells. Direct
operating expenses include all costs associated with production, marketing and
distribution, including all selling and direct overhead other than costs of
general corporate activities.

Historical financial information reflecting financial position, results of
operations, and cash flows of the Property is not presented because the purchase
price was assigned to the oil and gas property interests and related equipment
acquired. Other assets acquired and liabilities assumed were not material. In
addition, the Property was a part of much larger enterprises prior to the
acquisition by the Company and representative amounts of general and
administrative expenses, depreciation, depletion and amortization, interest and
other indirect costs were not necessarily allocated to the Property acquired,
nor would such allocated historical costs be relevant to future operations of
the Property. Development and exploration expenditures related to the Property
were insignificant in the relevant period. Accordingly, the historical statement
of revenues and direct operating expenses of Unocal's interest in the Property
is presented in lieu of the financial statements required under Item 3-05 of
Securities and Exchange Commission Regulation S-X.

The presented statement of revenues and direct operating expenses of the
net 30% interest acquired for the three months ended March 31, 2000 is
unaudited; however, it includes all adjustments (consisting only of normal
recurring adjustments) which, in the opinion of the Company's management, are
necessary for a fair presentation for such period. Accounting measurements at
interim dates inherently involve greater reliance on estimates than at year end.
The results of operations for the interim period presented are not necessarily
indicative of the results to be expected for the entire year.

The preparation of the financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that effect the reported amounts of revenue and expenses during the
reporting periods. Actual results could differ from those estimates.

(2) SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)

The following reserve estimates present the Company's estimate of the
proven oil and gas reserves and net cash flow of the Property which is an
offshore United States property. The Company emphasizes that reserve estimates
are inherently imprecise and that estimates of new discoveries are more
imprecise than those of producing oil and gas properties. Accordingly, the
estimates are expected to change as future information becomes available.

F-25
<PAGE> 105
30% INTEREST
SOUTH TIMBALIER BLOCK 26

NOTES TO FINANCIAL STATEMENTS

(a) Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped
reserves and proved developed reserves of the Property.

<TABLE>
<CAPTION>
OIL GAS
(MBBLS) (MMCF)
------- ------
<S> <C> <C>
Proved developed and undeveloped reserves:
April 1, 1998:............................................ 1,730 4,106
Production............................................. (110) (164)
----- -----
December 31, 1998:........................................ 1,620 3,942
Revisions of previous estimates........................ 176 159
Production............................................. (288) (352)
----- -----
December 31, 1999......................................... 1,508 3,749
----- -----
Proved developed reserves:
December 31, 1998......................................... 1,360 2,533
December 31, 1999......................................... 1,273 1,914
</TABLE>

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil & Gas Reserves

The Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves (Standardized Measure) is a disclosure requirement
under Statement of Financial Accounting Standards No. 69.

The Standardized Measure of Discounted Future Net Cash Flows does not
purport to be, nor should it be interpreted to present, the fair value of the
oil and gas reserves of the properties. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, the value of unproved properties, and consideration of
expected future economic and operating conditions.

The estimates of future cash flows and future production and development
costs are based on period-end sales prices for oil and gas, estimated future
production of proved reserves and estimated future production and development
costs of proved reserves, based on current costs and economic conditions. Future
income tax expense is based on the Company's tax basis in the property acquired.
The estimated future net cash flows are then discounted at a rate of 10%.

The Standardized Measure of Discounted Future Net Cash Flows relating to
proved oil and gas reserves is as follows (in thousands):

<TABLE>
<CAPTION>
1998 1999
------- --------
<S> <C> <C>
Future cash inflows......................................... $19,648 $ 47,123
Future production costs................................... (3,263) (10,959)
Future development and abandonment cost................... (9,547) (8,780)
Future income tax expense................................. (1,983) (8,011)
------- --------
Future net cash flows....................................... 4,855 19,373
10% annual discount for estimated timing of cash flows...... (2,023) (3,459)
------- --------
Standardized measure of discounted future net cash flows.... $ 2,832 $ 15,914
======= ========
</TABLE>

F-26
<PAGE> 106
30% INTEREST
SOUTH TIMBALIER BLOCK 26

NOTES TO FINANCIAL STATEMENTS

Changes in the Standardized Measure of discounted future net cash flows
(before income taxes) relating to proved oil and gas reserves is as follows (in
thousands):

<TABLE>
<CAPTION>
1998 1999
-------- -------
<S> <C> <C>
Beginning of period......................................... $ 17,655 $ 2,832
Sales of oil and gas produced, net of production expenses... (1,397) (6,201)
Changes in prices and production costs...................... (12,969) 20,257
Accretion of discount....................................... 1,030 4,999
Net change in income taxes.................................. (1,487) (5,973)
-------- -------
End of period............................................... $ 2,832 $15,914
======== =======
</TABLE>

Estimates of economically recoverable gas and oil reserves and of future
net revenues are based upon a number of variable factors and assumptions, all of
which are to some degree speculative and may vary considerable from actual
results. Therefore, actual production, revenues, development and operating
expenditures may not occur as estimated. The reserve data are estimates only,
are subject to many uncertainties and are based on data gained from production
histories and on assumptions as to geologic formations and other matters. Actual
quantities of gas and oil may differ materially from the amounts estimated.

F-27
<PAGE> 107

INDEPENDENT AUDITORS' REPORT

The Board of Directors
Energy Partners, Ltd.:

We have audited the accompanying statements of revenues and direct
operating expenses of Ocean Energy Inc.'s 98.5% Interest in the East Bay Complex
for the three years ended December 31, 1999, acquired by Energy Partners, Ltd.
These financial statements are the responsibility of Ocean Energy, Inc.'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 audits to obtain
reasonable assurance about whether the statements of revenues and direct
operating expenses are free of material misstatement. An audit of a statement of
revenues and direct operating expenses includes examining, on a test basis,
evidence supporting the amounts and disclosures in that financial statement. An
audit of a statement of revenues and direct operating expenses 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 of the statements of revenues and direct operating
expenses provide a reasonable basis for our opinion.

In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of Ocean Energy, Inc.'s 98.5% Interest in the East Bay
Complex as described in Note 1 for the three years ended December 31, 1999, in
conformity with generally accepted accounting principles.

KPMG LLP

New Orleans, Louisiana
May 31, 2000

F-28
<PAGE> 108

OCEAN ENERGY, INC.'S 98.5% INTEREST IN THE
EAST BAY COMPLEX

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE THREE YEARS ENDED DECEMBER 31, 1999 AND
THE THREE MONTHS ENDED MARCH 31, 2000

<TABLE>
<CAPTION>
2000
1997 1998 1999 (UNAUDITED)
------------ ----------- ----------- -----------
<S> <C> <C> <C> <C>
Revenues -- oil and gas sales........ $146,449,367 $83,103,978 $62,026,819 $23,136,432
Direct operating expenses............ 38,247,764 34,937,322 24,181,396 7,244,802
------------ ----------- ----------- -----------
Excess of revenues over direct
operating expenses................. $108,201,603 $48,166,656 $37,845,423 $15,891,630
============ =========== =========== ===========
</TABLE>

See accompanying notes to statements of revenues and direct operating expenses.

F-29
<PAGE> 109

OCEAN ENERGY INC.'S 98.5% INTEREST
IN THE EAST BAY COMPLEX

NOTES TO FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct
operating expenses of Ocean Energy, Inc.'s (OEI) 98.5% interest in the East Bay
Complex (the Property) for the three years ended December 31, 1999. The Property
was purchased by Energy Partners, Ltd. (the Company) on March 31, 2000 for
approximately $78 million. The Property consists of royalty and working
interests.

The accompanying statements of revenues and direct operating expenses of
the Property do not include general and administrative expenses, interest
expense, depreciation, depletion and amortization, or any provision for income
taxes since historical expenses of this nature incurred by OEI are not
necessarily indicative of the costs to be incurred by the Company.

Historical financial information reflecting financial position, results of
operations, and cash flows of the Property is not presented because the purchase
price was assigned to the oil and gas property interests and related equipment
acquired. Other assets acquired and liabilities assumed were not material. In
addition, the Property was a part of a much larger enterprise prior to the
acquisition by the Company, and representative amounts of general and
administrative expenses, depreciation, depletion and amortization, interest and
other indirect costs were not necessarily allocated to the Property acquired,
nor would such allocated historical costs be relevant to future operations of
the Property. Development and exploration expenditures related to the Property
were insignificant in the relevant period. Accordingly, the historical
statements of revenues and direct operating expenses of OEI's interest in the
Property are presented in lieu of the financial statements required under Item
3-05 of Securities and Exchange Commission Regulation S-X.

The presented statement of revenues and direct operating expenses of the
interest acquired for the three months ended March 31, 2000 is unaudited;
however, it includes all adjustments (consisting only of normal recurring
adjustments) which, in the opinion of the Company's management, are necessary
for a fair presentation for such period. Accounting measurements at interim
dates inherently involve greater reliance on estimates than at year end. The
results of operations for the interim period presented are not necessarily
indicative of the results to be expected for the entire year.

(2) SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)

F-30
<PAGE> 110
OCEAN ENERGY INC.'S 98.5% INTEREST
IN THE EAST BAY COMPLEX

NOTES TO FINANCIAL STATEMENTS

(a) Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped
reserves and proved developed reserves of the Property.

<TABLE>
<CAPTION>
OIL GAS
(MBBLS) (MMCF)
------- -------
<S> <C> <C>
Proved developed and undeveloped reserves:
December 31, 1996:........................................ 31,583 61,170
Revisions of previous estimates........................ (1,974) 6,628
Production............................................. (5,458) (16,343)
------ -------
December 31, 1997:........................................ 24,151 51,455
Revisions of previous estimates........................ (3,625) (823)
Production............................................. (4,844) (12,912)
------ -------
December 31, 1998:........................................ 15,682 37,720
Revisions of previous estimates........................ 10,188 (3,392)
Production............................................. (3,145) (6,247)
------ -------
December 31, 1999......................................... 22,725 28,081
Proved developed reserves:
December 31, 1997......................................... 21,145 41,183
December 31, 1998......................................... 14,590 32,749
December 31, 1999......................................... 21,196 22,887
</TABLE>

(b) Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil & Gas Reserves

The Standardized Measure of Discounted Future Net Cash Flows does not
purport to be, nor should it be interpreted to present, the fair value of the
oil and gas reserves of the Property. An estimate of fair value would also take
into account, among other things, the recovery of reserves not presently
classified as proved, the value of unproved properties, and consideration of
expected future economic and operating conditions.

F-31
<PAGE> 111
OCEAN ENERGY INC.'S 98.5% INTEREST
IN THE EAST BAY COMPLEX

NOTES TO FINANCIAL STATEMENTS

The Standardized Measure of Discounted Future Net Cash Flows relating to
proved oil and gas reserves is as follows (in thousands):

<TABLE>
<CAPTION>
1997 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflows.................................. $ 549,463 $ 246,531 $ 616,728
Future production costs............................ (246,393) (137,192) (276,737)
Future development and abandonment cost............ (126,865) (96,582) (117,331)
Future income tax expense.......................... (41,056) (2,972) (51,929)
--------- --------- ---------
Future net cash flows................................ 135,149 9,785 170,731
10% annual discount for estimated timing of cash
flows.............................................. (17,850) 10,949 (53,665)
--------- --------- ---------
Standardized measure of discounted future net cash
flows.............................................. $ 117,299 $ 20,734 $ 137,066
========= ========= =========
</TABLE>

Changes in the Standardized Measure of discounted future net cash flows
(before income taxes) relating to proved oil and gas reserves is as follows (in
thousands):

<TABLE>
<CAPTION>
1997 1998 1999
--------- -------- --------
<S> <C> <C> <C>
Beginning of period............................... $ 434,010 $117,299 $ 20,734
Sales of oil and gas produced, net of production
expenses........................................ (108,022) (48,167) (37,845)
Changes in prices and production costs............ (183,021) (84,699) 199,067
Accretion of discount............................. 11,077 2,216 (1,064)
Net change in income taxes........................ (36,745) 34,085 (43,826)
--------- -------- --------
End of period..................................... $ 117,299 $ 20,734 $137,066
========= ======== ========
</TABLE>

Estimates of economically recoverable gas and oil reserves and of future
net revenues are based upon a number of variable factors and assumptions, all of
which are to some degree speculative and may vary considerably from actual
results. Therefore, actual production, revenues, development and operating
expenditures may not occur as estimated. The reserve data are estimates only,
are subject to many uncertainties and are based on data gained from production
histories and on assumptions as to geologic formations and other matters. Actual
quantities of gas and oil may differ materially from the amounts estimated.

F-32
<PAGE> 112

APPENDIX A
REPORT OF INDEPENDENT PETROLEUM ENGINEERS

[LETTERHEAD OF NETHERLAND, SEWELL & ASSOCIATES, INC.]

July 27, 2000

Mr. James E. Orth
Energy Partners, Ltd.
Suite 3400
201 St. Charles Avenue
New Orleans, Louisiana 70170

Dear Mr. Orth:

In accordance with your request, we have estimated the proved reserves and
future revenue, as of January 1, 2000, to the Energy Partners, Ltd. (EPL)
interest in certain oil and gas properties located in Bay Marchand, Main Pass
122/133, South Pass 24/27/39, South Timbalier 26, and South Timbalier 27 Fields,
state and federal waters offshore Louisiana, as listed in the accompanying
tabulations. This report has been prepared using constant prices and costs and
conforms to the guidelines of the Securities and Exchange Commission (SEC).

As presented in the accompanying summary projections, Tables I through IV,
we estimate the net reserves and future net revenue to the EPL interest, as of
January 1, 2000, to be:

<TABLE>
<CAPTION>
NET RESERVES FUTURE NET REVENUE
NET GAS ------------------------ ----------------------------
PRODUCED OIL GAS SOLD(1) PRESENT WORTH
CATEGORY (MCF) (BARRELS) (MCF) TOTAL AT 10%
-------- ---------- ---------- ----------- ------------ -------------
<S> <C> <C> <C> <C> <C>
Proved Developed
Producing.................. 22,082,426 16,999,350 1,259,888 $109,261,400 $113,795,300
Non-Producing.............. 36,231,678 7,991,757 31,215,870 162,343,200 111,677,000
Proved Undeveloped........... 12,711,970 3,049,084 12,127,491 54,811,400 33,053,100
---------- ---------- ---------- ------------ ------------
Total Proved....... 71,026,074 28,040,191 44,603,249 $326,416,000 $258,525,400
</TABLE>

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

(1) Net gas sold reserves include the effect of gas consumed in operations.

The oil reserves shown include crude oil and condensate. Oil volumes are
expressed in barrels which are equivalent to 42 United States gallons. Gas
volumes are expressed in thousands of standard cubic feet (MCF) at the contract
temperature and pressure bases. Gas sales volumes at Bay Marchand Field are
based on produced wet gas volumes. Gas sales volumes at Main Pass 122/133 Field
are adjusted for shrinkage to account for fuel, flare, and processing losses.
The gas price for Main Pass 122/133 properties is adjusted to include the effect
of natural gas liquids revenue. Gas sales volumes at South Pass 24/27/39 Field
are adjusted for our estimates of shrinkage to account for fuel and flare
losses. Gas sales volumes at South Timbalier 26 Field are adjusted for EPL's
estimates of shrinkage to account for fuel and flare losses.

This report includes summary projections of reserves and revenue for each
reserve category. For the purposes of this report, the term "lease" refers to a
single economic projection.

The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, and proved
undeveloped reserves. In accordance with SEC guidelines, our estimates do not
include any value for probable or possible reserves which may exist for these
properties. This report does not include any value which could be attributed to
interests in undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated.

Future gross revenue to the EPL interest is prior to deducting state
production taxes. Future net revenue is after deducting these taxes, future
capital costs, and operating expenses, but before

A-1
<PAGE> 113

[LETTERHEAD OF NETHERLAND, SEWELL & ASSOCIATES, INC.]

consideration of federal income taxes; future net revenue for South Pass
24/27/39, South Timbalier 26, and South Timbalier 27 Fields is also after
deducting abandonment costs. In accordance with SEC guidelines, the future net
revenue has been discounted at an annual rate of 10 percent to determine its
"present worth." The present worth is shown to indicate the effect of time on
the value of money and should not be construed as being the fair market value of
the properties.

For the purposes of this report, a field inspection of the properties has
not been performed nor has the mechanical operation or condition of the wells
and their related facilities been examined. We have not investigated possible
environmental liability related to the properties; therefore, our estimates do
not include any costs which may be incurred due to such possible liability. Our
estimates of future revenue do not include any salvage value for the lease and
well equipment nor the cost to abandon the Bay Marchand or Main Pass 122/133
properties. Future revenue estimates for South Pass 24/27/39, South Timbalier
26, and South Timbalier 27 properties also do not include any salvage value for
the lease and well equipment, but do include EPL's estimates of the costs to
abandon the wells, platforms, and production facilities. Abandonment costs are
included with other capital investments.

Oil prices used in this report are based on a December 31, 1999 NYMEX West
Texas Intermediate spot market price of $25.60 per barrel, adjusted by lease for
gravity, transportation fees, and regional price differentials. Gas prices used
in this report are based on a December 31, 1999 NYMEX Henry Hub spot market
price of $2.33 per MMBTU, adjusted by lease for energy content, transportation
fees, and regional price differentials. Oil and gas prices are held constant in
accordance with SEC guidelines.

Lease and well operating costs are based on operating expense records of
EPL. Lease and well operating costs include only direct lease and field level
costs. As requested, these costs do not include the per-well overhead expenses
allowed under joint operating agreements nor do they include the headquarters
general and administrative overhead expenses of EPL. Lease and well operating
costs are held constant in accordance with SEC guidelines. Capital costs are
included as required for workovers, new development wells, and production
equipment.

We have made no investigation of potential gas volume and value imbalances
which may have resulted from overdelivery or underdelivery to the EPL interest.
Therefore, our estimates of reserves and future revenue do not include
adjustments for the settlement of any such imbalances; our projections are based
on EPL receiving its net revenue interest share of estimated future gross gas
production.

The reserves included in this report are estimates only and should not be
construed as exact quantities. They may or may not be recovered; if recovered,
the revenues therefrom and the costs related thereto could be more or less than
the estimated amounts. A substantial portion of these reserves are for behind
pipe zones, undeveloped locations, and producing wells that lack sufficient
production history upon which performance-related estimates of reserves can be
based. Therefore, these reserves are based on estimates of reservoir volumes and
recovery efficiencies along with analogies to similar production. As such
reserve estimates are usually subject to greater revision than those based on
substantial production and pressure data, it may be necessary to revise these
estimates up or down in the future as additional performance data become
available. The sales rates, prices received for the reserves, and costs incurred
in recovering such reserves may vary from assumptions included in this report
due to governmental policies and uncertainties of supply and demand. Also,
estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we
have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological data;
therefore, our conclusions necessarily represent only informed professional
judgments.

A-2
<PAGE> 114

[LETTERHEAD OF NETHERLAND, SEWELL & ASSOCIATES, INC.]

The titles to the properties have not been examined by Netherland, Sewell &
Associates, Inc., nor has the actual degree or type of interest owned been
independently confirmed. The data used in our estimates were obtained from
Energy Partners, Ltd. and the nonconfidential files of Netherland, Sewell &
Associates, Inc. and were accepted as accurate. We are independent petroleum
engineers, geologists, and geophysicists; we do not own an interest in these
properties and are not employed on a contingent basis. Basic geologic and field
performance data together with our engineering work sheets are maintained on
file in our office.

Very truly yours,

/s/ FREDERIC D. SEWELL

JND: CLM

A-3
<PAGE> 115

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

Through and including , 2000 (the 25th day after the date of this
prospectus), all dealers effecting transactions in these securities, whether or
not participating in this offering, may be required to deliver a prospectus.
This is in addition to the dealers' obligation to deliver a prospectus when
acting as underwriters and with respect to their unsold allotments or
subscriptions.

5,750,000 SHARES

ENERGY PARTNERS, LTD.

COMMON STOCK

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

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

MERRILL LYNCH & CO.

UBS WARBURG LLC

DONALDSON, LUFKIN & JENRETTE

HOWARD WEIL
A DIVISION OF LEGG MASON WOOD WALKER, INC.

, 2000

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE> 116

SUBJECT TO COMPLETION

PRELIMINARY PROSPECTUS DATED SEPTEMBER 21, 2000

P R O S P E C T U S

5,750,000 SHARES

[LOGO]
ENERGY PARTNERS, LTD.
COMMON STOCK
----------------------

This is our initial public offering. We are selling all of the shares. The
international managers are offering 1,150,000 shares outside the U.S. and Canada
and the U.S. underwriters are offering 4,600,000 shares in the U.S. and Canada.

We expect the public offering price to be between $17.00 and $19.00 per
share. Currently, no public market exists for the shares. After pricing of the
offering, we expect that the shares will trade on the New York Stock Exchange
under the symbol "EPL."

INVESTING IN OUR COMMON STOCK INVOLVES RISKS THAT ARE DESCRIBED IN THE
"RISK FACTORS" SECTION BEGINNING ON PAGE 10 OF THIS PROSPECTUS.

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

The international managers may also purchase up to an additional 172,500
shares at the public offering price, less the underwriting discount, within 30
days from the date of this prospectus to cover over-allotments. The U.S.
underwriters may similarly purchase up to an aggregate of an additional 690,000
shares from us.

The shares will be ready for delivery on or about , 2000.

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

MERRILL LYNCH INTERNATIONAL UBS AG

DONALDSON, LUFKIN & JENRETTE HOWARD WEIL
A DIVISION OF LEGG MASON WOOD WALKER, INC.

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

The date of this prospectus is , 2000.
<PAGE> 117

UNDERWRITING

We intend to offer the shares outside the U.S. and Canada through the
international managers and in the U.S. and Canada through the U.S. underwriters.
Merrill Lynch International and UBS AG are acting as lead managers for the
international managers named below. Subject to the terms and conditions
described in an international purchase agreement among us and the international
managers, and concurrently with the sale of 4,600,000 shares to the U.S.
underwriters, we have agreed to sell to the international managers, and the
international managers severally have agreed to purchase from us, the number of
shares listed opposite their names below.

<TABLE>
<CAPTION>
NUMBER
INTERNATIONAL MANAGER OF SHARES
------------------------------------------------------------ ---------
<S> <C>
Merrill Lynch International.................................
UBS AG......................................................
Donaldson, Lufkin & Jenrette International..................
Howard Weil, a Division of Legg Mason Wood Walker, Inc. ....
--------
Total.......................................... 1,150,000
========
</TABLE>

We have also entered into a U.S. purchase agreement with the U.S.
underwriters for sale of the shares in the U.S. and Canada for whom Merrill
Lynch, Pierce, Fenner & Smith Incorporated and UBS Warburg LLC are acting as
U.S. representatives. Subject to the terms and conditions in the U.S. purchase
agreement, and concurrently with the sale of 1,150,000 shares to the
international managers pursuant to the international purchase agreement, we have
agreed to sell to the U.S. underwriters, and the U.S. underwriters severally
have agreed to purchase 4,600,000 shares from us. The initial public offering
price per share and the total underwriting discount per share are identical
under the international purchase agreement and the U.S. purchase agreement.

The international managers and the U.S. underwriters have agreed to
purchase all of the shares sold under the international and U.S. purchase
agreements if any of these shares are purchased. If an underwriter defaults, the
U.S. and international purchase agreements provide that the purchase commitments
of the non-defaulting underwriters may be increased or the purchase agreements
may be terminated. The closings for the sale of shares to be purchased by the
international managers and the U.S. underwriters are conditioned on one another.

We have agreed to indemnify the international managers and the U.S.
underwriters against certain liabilities, including liabilities under the
Securities Act, or to contribute to payments the international mangers and U.S.
underwriters may be required to make in respect of those liabilities.

Other than the prospectus in electronic format, the information on the Web
sites is not part of this prospectus.
<PAGE> 118

COMMISSIONS AND DISCOUNTS

The lead managers have advised us that the international managers propose
initially to offer the shares to the public at the initial public offering price
on the cover page of this prospectus, and to dealers at that price less a
concession not in excess of $ per share. The international managers may
allow, and the dealers may reallow, a discount not in excess of $ per share
to other dealers. After the initial public offering, the public offering price,
concession and discount may be changed.

The following table shows the public offering price, underwriting discount
and proceeds before our expenses. The information assumes either no exercise or
full exercise by the international managers and the U.S. underwriters of their
over-allotment options.

The expenses of this offering, not including the underwriting discount, are
estimated at $1.2 million and are payable by us.

OVER-ALLOTMENT OPTIONS

We have granted an option to the international managers to purchase up to
172,500 additional shares at the public offering price less the underwriting
discount. The international managers may exercise this option for 30 days from
the date of this prospectus solely to cover any over-allotments. If the
international managers exercise this option, each international manager will be
obligated, subject to conditions contained in the purchase agreement, to
purchase a number of additional shares proportionate to that international
manager's initial amount reflected in the above table.

We have also granted an option to the U.S. underwriters, exercisable for 30
days from the date of this prospectus, to purchase up to 690,000 additional
shares to cover any over-allotments on terms similar to those granted to the
international managers.

INTERSYNDICATE AGREEMENT

The international managers and the U.S. underwriters have entered into an
intersyndicate agreement that provides for the coordination of their activities.
Under the intersyndicate agreement, the international managers and the U.S.
underwriters may sell shares to each other for purposes of resale at the initial
public offering price, less an amount not greater than the selling concession.
Under the intersyndicate agreement, the international managers and any dealer to
whom they sell shares will not offer to sell or sell shares to persons who are
U.S. or Canadian persons or to persons they believe intend to resell to persons
who are U.S. or Canadian persons, except in the case of transactions under the
intersyndicate agreement. Similarly, the U.S. underwriters and any dealer to
whom they sell shares will not offer to sell or sell shares to non-U.S. or
non-Canadian persons or to persons they believe intend to resell to non-U.S. or
non-Canadian persons, except in the case of transactions under the
intersyndicate agreement.

RESERVED SHARES

<PAGE> 119

NO SALES OF SIMILAR SECURITIES

- offer, pledge, sell or contract to sell any common stock,

- sell any option or contract to purchase any common stock,

- purchase any option or contract to sell any common stock,

- lend or otherwise dispose of or transfer any common stock,

- request or demand that we file a registration statement related to the
common stock, other than in connection with our employee benefit plan or
non-employee director stock option plan, or

LISTING

- the valuation multiples of publicly traded companies that the U.S.
representatives and the lead managers believe to be comparable to us,

- our financial information,

- the history of, and the prospects for, our company and the industry in
which we compete,

- an assessment of our management, its past and present operations, and the
prospects for, and timing of, our future revenues,

- the present state of our development, and

- the above factors in relation to market values and various valuation
measures of other companies engaged in activities similar to ours.

An active trading market for the shares may not develop. It is also
possible that after the offering the shares will not trade in the public market
at or above the initial public offering price.

The underwriters do not expect to sell more than 5% of the shares in the
aggregate to accounts over which they exercise discretionary authority.
<PAGE> 120

PRICE STABILIZATION, SHORT POSITIONS AND PENALTY BIDS

Until the distribution of the common shares is completed, the SEC rules may
limit the underwriters and selling group members from bidding for or purchasing
our common shares. However, the U.S. underwriters may engage in transactions
that stabilize the price of the common shares, such as bids or purchases that
peg, fix or maintain that price.

Similar to other purchase transactions, the U.S. underwriters purchases to
cover the syndicate short sales may have the effect of raising or maintaining
the market price of the common shares or preventing or retarding a decline in
the market price of the common shares. As a result, the price of the common
shares may be higher than the price that might otherwise exist in the open
market.

UK SELLING RESTRICTIONS

Each international manager has agreed that

- it has not offered or sold and 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 do not constitute an
offer to the public in the United Kingdom within the meaning of the
Public Offers of Securities Regulations 1995;

- 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

- it has only issued or passed on and will only issue or pass on in the
United Kingdom any document received by it in connection with the
issuance of common stock to a person who is of a kind described in
Article 11(3) of the Financial Services Act 1986 (Investment
Advertisements) (Exemptions) Order 1996 as amended by the Financial
Services Act 1986 (Investment
<PAGE> 121

Advertisements) (Exemptions) Order 1997 or is a person to whom such
document may otherwise lawfully be issued or passed on.

NO PUBLIC OFFERING OUTSIDE THE UNITED STATES

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 our company or shares of our common stock in any
jurisdiction where action for that purpose is required. Accordingly, the shares
of our 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 any such country or jurisdiction.

Purchasers of the shares offered by this prospectus 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 on the cover page of this
prospectus.

OTHER RELATIONSHIPS

<PAGE> 122

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

5,750,000 SHARES

[LOGO]

ENERGY PARTNERS, LTD.

COMMON STOCK

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

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

MERRILL LYNCH INTERNATIONAL

UBS AG

DONALDSON, LUFKIN & JENRETTE

HOWARD WEIL
A DIVISION OF LEGG MASON WOOD WALKER, INC.

, 2000

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE> 123

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The following is a list of the estimated costs and expenses, other than the
underwriting discount, to be incurred by Energy Partners, Ltd. in connection
with the distribution of the shares of common stock being registered hereby.
Except for the SEC Registration Fee, the National Association of Securities
Dealers, Inc. Filing Fee and the New York Stock Exchange Listing Fee, all
amounts are estimates.

<TABLE>
<S> <C>
SEC Registration Fee........................................ $ 33,169
National Association of Securities Dealers, Inc. Filing
Fee....................................................... 14,875
New York Stock Exchange Listing Fee......................... 161,801
Printing and Engraving Costs................................ 200,000
Accounting Fees and Expenses................................ 250,000
Legal Fees and Expenses (excluding Blue Sky)................ 500,000
Blue Sky Qualification Fees and Expenses.................... 10,000
Transfer Agent and Registrar Fees........................... 10,000
Miscellaneous Expenses...................................... 20,155
----------
Total............................................. $1,200,000
==========
</TABLE>

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

* To be provided by amendment.

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

General Corporation Law

Energy Partners, Ltd. is incorporated under the laws of the State of
Delaware. Section 145 ("Section 145") of the General Corporation Law of the
State of Delaware (the "DGCL") as the same exists or may hereafter be amended,
inter alia, provides that a Delaware corporation may indemnify any persons who
were, are or are threatened to be made, parties to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal, administrative or
investigative (other than an action by or in the right of such corporation), by
reason of the fact that such person is or was a director, officer, employee or
agent of such corporation, or is or was serving at the request of such
corporation as a director, officer, employee or agent of another corporation or
enterprise. The indemnity may include expenses (including attorneys' fees),
judgments, fines and amounts paid in settlement actually and reasonably incurred
by the person in connection with such action, suit or proceeding, provided such
person acted in good faith and in a manner he reasonably believed to be in or
not opposed to the corporation's best interests and, with respect to any
criminal action or proceeding, had no reasonable cause to believe that his
conduct was unlawful. A Delaware corporation may indemnify any persons who are,
were or are threatened to be made, a party to any threatened, pending or
completed action or suit by or in the right of the corporation by reasons of the
fact that such person was a director, officer, employee or agent of such
corporation, or is or was serving at the request of such corporation as a
director, officer, employee or agent of another corporation or enterprise. The
indemnity may include expenses (including attorneys' fees) actually and
reasonably incurred by such person in connection with the defense or settlement
of such action or suit, provided such person acted in good faith and in a manner
he reasonably believed to be in or not opposed to the corporation's best
interests, provided further that no indemnification is permitted without
judicial approval if the officer, director, employee or agent is adjudged to be
liable to the corporation. Where a present or former director or officer is
successful on the merits or otherwise in the defense of any action referred to
above, the corporation must indemnify him against the expenses which such
director or officer has actually and reasonably incurred.

Section 145 further authorizes a corporation to purchase and maintain
insurance on behalf of any person who is or was a director, officer, employee or
agent of the corporation, or is or was serving at the

II-1
<PAGE> 124

request of the corporation as a director, officer, employee or agent of another
corporation or other enterprise, against any liability asserted against him and
incurred by him in any such capacity, arising out of his status as such, whether
or not the corporation would have the power to indemnify him under Section 145.

Certificate of Incorporation

Our certificate of incorporation and bylaws provide for the indemnification
of directors, officers, employees and agents to the fullest extent permitted by
the DGCL.

All of our directors and officers will be covered by insurance policies
maintained by Energy Partners, Ltd. against some liabilities for actions taken
in their capacities as such, including liabilities under the Securities Act of
1933, as amended.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

(a) No securities of Energy Partners, Ltd. which were not registered under
the Securities Act have been sold by us within the past three years except as
follows (giving effect to a 1,500-for-1 stock split effective September 15,
2000):

(1) On February 26, 1998, we issued 2,475,000 shares of common stock
to an employee of ours for $1,650.00.

(2) On May 7, 1998, we issued an aggregate of 4,912,500 shares of
common stock to certain employees of ours for an aggregate of $3,275.00.

(3) On June 2, 1998, we issued 7,500,000 shares of common stock to
Energy Income Fund, L.P., for $5,000.00.

(4) On June 5, 1998, we issued an aggregate of 45,000 shares of common
stock to certain directors of ours for an aggregate of $30.00.

(5) On June 5, 1998 we issued 15,000 shares of common stock to Energy
Income Fund, L.P. for $10.00.

(6) On June 5, 1998, we issued 112,500 shares of common stock to an
employee of ours for $75.00.

(7) On November 17, 1999, we issued 500,000 shares of Series A
Convertible Preferred Stock and 100,000 shares of Series B Convertible
Preferred Stock to Evercore Capital Partners L.P. and its affiliates for an
aggregate of $60,000,000.

(8) On November 17, 1999 we issued a warrant to purchase 928,050
shares of our common stock to Energy Income Fund, L.P. in consideration of
the restructuring of the Energy Income Fund financing agreement.

(9) On April 17, 2000, we issued 90,000 shares of common stock, 60,000
of which are subject to vesting, and options to purchase 375,000 shares of
common stock, subject to vesting, to an employee of ours in connection with
an employment and stock ownership agreement.

(b) The issuances of the securities set forth above were deemed to be not
subject to registration under the Securities Act in reliance on Section 4(2) of
the Securities Act, in each case as transactions by an issuer not involving any
public offering.

II-2
<PAGE> 125

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) Exhibits:

See Exhibit Index at page II-5 of this Registration Statement.

(b) Financial Statement Schedules:

See Exhibit 27.1 of this Registration Statement.

ITEM 17. UNDERTAKINGS.

(1) The undersigned registrant hereby undertakes: to provide to the
underwriters at the closing specified in the underwriting agreements,
certificates in such denominations and registered in such names as required
by the underwriters to permit prompt delivery to each purchaser.

(2) Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers and controlling
persons of the registrant pursuant to the foregoing provisions, or
otherwise, the registrant has been advised that in the opinion of the SEC
such indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event that a claim
for indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or
controlling person in connection with the securities being registered, the
registrant will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against
public policy as expressed in the Securities Act and will be governed by
the final adjudication of such issue.

(3) The undersigned registrant hereby undertakes that:

(a) For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed as part
of this registration statement in reliance upon Rule 430A and contained
in a form of prospectus filed by the registrant pursuant to Rule
424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to
be part of this registration statement as of the time it was declared
effective.

(b) For the purpose of determining any liability under the
Securities Act, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating
to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering
thereof.

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<PAGE> 126

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Amendment No. 1 to the Registration Statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of New
Orleans, State of Louisiana, on September 21, 2000.

ENERGY PARTNERS, LTD.

By: /s/ RICHARD A. BACHMANN
----------------------------------
Name: Richard A. Bachmann
Title: Chairman, President and
Chief Executive
Officer

Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 1 to the registration statement has been signed by the following persons in
the capacities and on the dates indicated.

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>

* Chairman, President and Chief September 21, 2000
----------------------------------------------------- Executive Officer
Richard A. Bachmann (Principal Executive
Officer)

/s/ SUZANNE V. BAER Chief Financial Officer September 21, 2000
----------------------------------------------------- (Principal Accounting
Suzanne V. Baer Officer)

* Director September 21, 2000
-----------------------------------------------------
Austin M. Beutner

* Director September 21, 2000
-----------------------------------------------------
John Bumgarner, Jr.

* Director September 21, 2000
-----------------------------------------------------
Harold D. Carter

* Director September 21, 2000
-----------------------------------------------------
Robert D. Gershen

* Director September 21, 2000
-----------------------------------------------------
Eamon M. Kelly

* Director September 21, 2000
-----------------------------------------------------
John G. Phillips

* Director September 21, 2000
-----------------------------------------------------
Jeffrey R. Sechrest
</TABLE>

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

* Pursuant to Powers of Attorney filed with the SEC as Exhibit 24.1

By: /s/ SUZANNE V. BAER
Attorney-in-Fact
--------------------------------
Suzanne V. Baer,
Authorized Signatory

II-4
<PAGE> 127

INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
1.1** -- Form of U.S. Purchase Agreement between Energy Partners,
Ltd. and the U.S. Underwriters dated as of ,
2000.
1.2** -- Form of International Purchase Agreement between Energy
Partners, Ltd. and the International Underwriters dated
as of , 2000.
3.1 -- Restated Certificate of Incorporation of Energy Partners,
Ltd. dated as of November 16, 1999.
3.2 -- Amendment to Restated Certificate of Incorporation of
Energy Partners, Ltd. dated as of September 15, 2000.
3.3 -- Amended and Restated Bylaws of Energy Partners, Ltd.
dated as of September 12, 2000.
4.1 -- Certificate of Designations of the Series A Convertible
Preferred Stock of Energy Partners, Ltd. dated as of
November 16, 1999.
4.2 -- Certificate of Designations of the Series B Convertible
Preferred Stock of Energy Partners, Ltd. dated as of
November 16, 1999.
4.3 -- Certificate of Designations of the Series C Preferred
Stock of Energy Partners, Ltd. dated as of November 16,
1999.
4.4 -- Stockholder Agreement by and among Energy Partners, Ltd.,
Evercore Capital Partners L.P., Evercore Capital Partners
(NQ) L.P., Evercore Capital Offshore Partners L.P.,
Energy Income Fund, L.P. and the Individual Shareholders
of the Company Signatories Thereto dated as of November
17, 1999.
4.5 -- Registration Rights Agreement by and between Energy
Partners, Ltd., Evercore Capital Partners L.P., Evercore
Capital Partners (NQ) L.P., Evercore Capital Offshore
Partners L.P., Energy Income Fund, L.P. and the
Individual Shareholders of the Company Signatories
Thereto dated as of November 17, 1999.
4.6 -- Common Stock Purchase Warrant of Energy Partners, Ltd.
held by Energy Income Fund, L.P. dated as of November 17,
1999.
5.1** -- Opinion of Cahill Gordon & Reindel regarding the legality
of the securities being registered.
10.1* -- Financing Agreement by and between Energy Partners, Ltd.
and Energy Income Fund, L.P. dated as of April 15, 1998.
10.2* -- First Amendment to Financing Agreement by and among
Energy Partners, Ltd. and Energy Income Fund, L.P. dated
as of June 19, 1998.
10.3* -- Second Amendment to Financing Agreement by and among
Energy Partners, Ltd. and Energy Income Fund, L.P. dated
as of August 31, 1998.
10.4* -- Third Amendment to Financing Agreement by and among
Energy Partners, Ltd. and Energy Income Fund, L.P. dated
as of February 10, 1999.
10.5 -- Fourth Amendment to Financing Agreement by and between
Energy Partners, Ltd. and Energy Income Fund, L.P. dated
as of November 17, 1999.
10.6* -- Fifth Amendment to Financing Agreement by and between
Energy Partners, Ltd. and Energy Income Fund, L.P. dated
as of March 31, 2000.
10.7* -- Common Stock Purchase Agreement by and among Energy
Partners, Ltd. and Energy Income Fund, L.P. dated as of
May 7, 1998.
</TABLE>

II-5
<PAGE> 128

<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
10.8 -- Stock Purchase Agreement by and among Energy Partners,
Ltd., Evercore Capital Partners L.P., Evercore Capital
Partners (NQ) L.P. and Evercore Capital Offshore Partners
L.P. dated as of October 26, 1999.
10.9 -- Patent License Agreement between VTV, Incorporated and
Energy Partners, Ltd. dated as of May 16, 1998.
10.10 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Richard A. Bachmann dated as of
June 5, 1998.
10.11 -- First Amendment to Employment and Stock Ownership
Agreement by and between Energy Partners, Ltd. and
Richard A. Bachmann dated as of November 17, 1999.
10.12 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Suzanne V. Baer dated as of
March 18, 2000.
10.13* -- Form of Employment and Stock Ownership Agreement by and
between Energy Partners, Ltd. and Clinton W. Coldren,
Wayne A. Greenwalt, John H. McCandless and James E. Orth
dated as of June 5, 1998.
10.14 -- Amendment to Employment and Stock Ownership Agreement by
and between Energy Partners, Ltd. and Wayne A. Greenwalt
dated as of March 4, 1999.
10.15* -- Form of First Amendment to Employment and Stock Ownership
Agreement by and between Energy Partners, Ltd. and
Clinton W. Coldren, Wayne A. Greenwalt, John H.
McCandless and James E. Orth dated as of November 17,
1999.
10.16* -- Form of Stock Ownership Agreement by and between Energy
Partners, Ltd. and Harold D. Carter, Eamon Kelly and John
G. Phillips dated as of June 5, 1998.
10.17 -- Reducing Revolving Credit Agreement among Energy
Partners, Ltd., Bank One Texas, N.A. and the several
banks and financial institutions from time to time
parties thereto dated as of March 30, 2000.
10.18 -- Purchase and Sale Agreement by and between Ocean Energy,
Inc. and Energy Partners, Ltd. dated as of January 26,
2000.
10.19 -- Farmout Agreement by and between Chevron U.S.A. Inc.,
Kewanee Industries, Inc. and Energy Partners, Ltd. dated
as of June 9, 1998.
10.20 -- Purchase and Sale Agreement between Union Oil Company of
California and Energy Partners, Ltd. dated as of March
31, 2000.
10.21* -- Asset Purchase Agreement by and between Shell Offshore
Inc., Shell Oil & Gas Investment Limited Partnership,
Shell Consolidated Energy Resources Inc., Shell Frontier
Oil & Gas Inc., Energy Partners, Ltd. and Union Oil
Company of California, dated as of June 23, 1998.
10.22 -- Purchase and Sale Agreement between Energy Partners Ltd.
and Vastar Resources, Inc. dated as of April 20, 2000.
10.23 -- Alliance Agreement, Production Operations and Maintenance
Services, by and between Production Management
Corporation and Energy Partners, Ltd. dated as of June 4,
1998.
10.24* -- Amendment to Alliance Agreement, Production Operations
and Maintenance Services, by and between Production
Management Corporation and Energy Partners, Ltd. dated as
of May 17, 2000.
10.25 -- 2000 Long Term Stock Incentive Plan adopted on September
12, 2000.
10.26 -- 2000 Stock Option Plan for Non-Employee Directors adopted
on September 12, 2000.
</TABLE>

II-6
<PAGE> 129

<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
10.27 -- Stock and Deferral Plan for Non-Employee Directors
adopted on September 12, 2000.
10.28 -- First Amendment to Reducing Revolving Credit Agreement
among Energy Partners, Ltd., Bank One, Texas, N.A., The
Chase Manhattan Bank, BNP Paribas and Whitney National
Bank dated as of August 10, 2000.
10.29 -- Letter of Intent between Energy Partners, Ltd. and Brown
& Root Energy Services dated as of August 4, 2000.
21.1* -- Subsidiaries of Energy Partners, Ltd.
23.1 -- Consent of KPMG LLP, Independent Certified Public
Accountants.
23.2** -- Consent of Cahill Gordon & Reindel (included in Exhibit
5.1).
23.3 -- Consent of Netherland, Sewell & Associates, Inc.
24.1* -- Powers of Attorney authorizing execution of Registration
Statement on Form S-1 on behalf of certain officers and
directors of Energy Partners Ltd. (included on the
signature page to this registration statement).
27.1 -- Financial Data Schedule.
99.1 -- Report of Independent Petroleum Engineers dated as of
August 21, 2000.
</TABLE>

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

* Previously filed.

** To be included by amendment.

II-7