ENERGY PARTNERS LTD - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER: 001-16179
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ENERGY PARTNERS, LTD.
(Exact name of registrant as specified in its charter)

DELAWARE 72-1409562
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)

201 ST. CHARLES AVENUE, SUITE 3400 70170
NEW ORLEANS, LOUISIANA (Zip Code)
(Address of principal executive offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
504-569-1875

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Acts). Yes [X] No [ ]

The aggregate market value of the voting stock held by non-affiliates of
the registrant at June 28, 2002 based on the closing price of such stock as
quoted on the New York Stock Exchange on that date was $94,092,183.

As of February 28, 2003 there were 27,658,801 shares of the registrant's
common stock, par value $0.01 per share, outstanding.

Documents incorporated by reference: Portions of the registrant's
definitive proxy statement for its 2003 Annual Meeting of Stockholders have been
incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS

1

FORWARD LOOKING STATEMENTS

All statements other than statements of historical fact contained in this
Report and other periodic reports filed by us under the Securities Exchange Act
of 1934 and other written or oral statements made by us or on our behalf, are
forward-looking statements. When used herein, the words "anticipates",
"expects", "believes", "goals", "intends", "plans", or "projects" and similar
expressions are intended to identify forward-looking statements. It is important
to note that forward-looking statements are based on a number of assumptions
about future events and are subject to various risks, uncertainties and other
factors that may cause our actual results to differ materially from the views,
beliefs and estimates expressed or implied in such forward-looking statements.
We refer you specifically to the section "Additional Factors Affecting Business"
in Items 1 and 2 of this Report. Although we believe that the assumptions on
which any forward-looking statements in this Report and other periodic reports
filed by us are reasonable, no assurance can be given that such assumptions will
prove correct. All forward-looking statements in this Report are expressly
qualified in their entirety by the cautionary statements in this paragraph and
elsewhere in this Report.

PART I

ITEMS 1 & 2. BUSINESS AND PROPERTIES

We are an independent oil and natural gas exploration and production
company focused on the shallow to moderate depth waters of the Gulf of Mexico
Shelf. We concentrate on the Gulf of Mexico Shelf region because that area
provides us with favorable geologic and economic conditions, including multiple
reservoir formations, regional economies of scale, extensive infrastructure and
comprehensive geologic databases. We believe that this region offers a balanced
and expansive array of existing and prospective exploration, exploitation and
development opportunities in both established productive horizons and deeper
geologic formations. As of December 31, 2002, we had estimated proved reserves
of approximately 127.0 Bcf of natural gas and 26.4 million barrels of oil, or an
aggregate of approximately 47.5 million Boe, with a present value of estimated
pre-tax future net cash flows of $608.3 million and after-tax future net cash
flows of $476.9 million based upon year-end 2002 prices and a discount rate of
10%.

We were incorporated in January 1998 by Richard A. Bachmann, our founder,
chairman, president and chief executive officer. Mr. Bachmann, the former
president and chief operating officer of The Louisiana Land and Exploration
Company ("LL&E"), 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 this team provided us with access to the
operators of the Gulf of Mexico Shelf fields that became our cornerstone assets.
These relationships continue to provide us with a strategic advantage as we
pursue our strategy of being a consolidator of assets in the Gulf of Mexico
Shelf region.

We have grown our company through a combination of exploration,
exploitation and development drilling and multi-year, multi-well drill-to-earn
programs, as well as strategic acquisitions of mature oil and gas fields in the
Gulf of Mexico Shelf area, and in early 2002, the acquisition of Hall-Houston
Oil Company ("HHOC"). We intend to continue this strategy as part of our
multi-tiered focus.

On November 1, 2000, we consummated our initial public offering of 5.75
million shares of common stock, raising $80.2 million. Our common shares trade
on the New York Stock Exchange under the symbol "EPL." We maintain a website at
www.eplweb.com which contains information about us including links to our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and all related amendments. Our web site and the information contained in it and
connected to it shall not be deemed incorporated by reference into this Report
on Form 10-K.

ACQUISITION OF HALL-HOUSTON OIL COMPANY

On January 15, 2002, we closed the acquisition of HHOC and certain
affiliated interests. At closing, we issued $38.4 million liquidation preference
of newly authorized Series D Exchangeable Convertible Preferred

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Stock, with a fair value of $34.7 million, discounted to effect the increasing
dividend rate, $38.4 million of 11% Senior Subordinated Notes ("the Notes") due
2009 (immediately callable at par) and 574,931 shares of common stock. We also
paid $5.1 million of cash, assumed HHOC's working capital deficit and issued
warrants, with a fair market value of approximately $3.0 million, to purchase
four million shares of common stock. Former preferred stockholders of HHOC also
received the right to receive contingent consideration related to future proved
reserve additions generally to come from certain exploratory prospect acreage
held by HHOC as of the closing date.

The acquisition of HHOC strengthened our management team, expanded our
property base, reduced our geographic concentration, and moved us to a more
balanced oil and natural gas reserves and production profile. It also expanded
our technical knowledge base through the addition of quality personnel and
geophysical and geological data. Furthermore, the acquisition significantly
improved our portfolio of exploration opportunities by adding 12 offshore
exploratory blocks to complement our development and drill-to-earn portfolio.
Through the acquisition, we added proved reserves of 59.1 Bcfe, of which 98%
were natural gas and approximately 60% were proved developed as of the date of
acquisition.

CAPITAL EXPENDITURES

Our capital expenditures for 2002 totaled $68.1 million for exploration and
development activities. For 2003, we have budgeted exploration and development
expenditures of approximately $90 million. This budget includes a mixture of
lower risk development and exploitation wells, moderate risk exploration
opportunities and higher risk, higher potential exploration projects.

OUR PROPERTIES

At December 31, 2002, we had interests in 19 producing fields and 5 fields
under development, all of which are located in the Gulf of Mexico Shelf region
in water depths ranging from 3 to 476 feet. These fields fall into three focus
areas which we identify as our Eastern, Central and Western areas. The Eastern
area is comprised of the East Bay and Main Pass fields. The Central area is
comprised of five fields, three of which are contiguous and together cover most
of the Bay Marchand salt dome located in state and federal waters offshore
Louisiana and two of which are in federal waters and were acquired in the
acquisition of HHOC. The Western area is comprised of 12 producing fields
consisting primarily of those acquired in the acquisition of HHOC and those 2002
lease acquisitions on which we drilled successful exploratory wells.

EASTERN AREA

EAST BAY FIELD

In March 2000, we acquired the East Bay field, and related production,
compression and storage facilities for $72.3 million. East Bay is located 89
miles southeast of New Orleans near the mouth of the Mississippi River and
contains producing wells located onshore along the coastline and in water depths
ranging up to approximately 85 feet. The field encompasses nearly 48 square
miles and is comprised of three primary oil and natural gas fields, South Pass
24, 27 and 39. Through two state lease sales in 2001 and the March 2002 federal
lease sale, we acquired acreage that is contiguous to East Bay in several
additional South Pass blocks. We are the operator of these fields and own an
average 96.3% working interest. Our net revenue interest ranges from 42% to 86%.
Inclusive of all lease acquisitions, our lease area covers 31,703 gross acres
(30,525 net acres) of which 4,330 gross and net acres are under federal
jurisdiction, while 27,373 gross acres (26,195 net acres) are under the
jurisdiction of the State of Louisiana. In addition, we have 3,525 gross and net
undeveloped acres under federal jurisdiction and 6,811 gross and net undeveloped
acres under the jurisdiction of the State of Louisiana.

During 2002, we invested a total of $18.1 million in the drilling or
sidetracking of four wells, all of which were successful, and the workover or
recompletion of 14 wells, 9 of which were successful. Eastern area production
accounted for approximately 52% of our net daily production during 2002.

During 2001, we increased our seismic coverage in the area and merged the
various surveys covering East Bay. We believe that the new 3-D data-set has and
will continue to provide improved structural and stratigraphic

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interpretation for additional drilling activity. Utilizing this data, we have
already identified 13 new exploratory prospects and leads in and around the East
Bay field. The first three of these prospects, Mesa Verde, Yosemite and Arches,
were drilled in 2002. Mesa Verde was completed and placed on production in
December 2002. The Yosemite prospect was drilled in December 2002, while the
Arches well was completed in its deeper, proved undeveloped objective in January
2003, with both having commenced production in February 2003.

We also drilled a development well, the Whale prospect, that was a
sidetrack and redrill of a well that had been drilled by the field's previous
owner and abandoned due to mechanical problems. This well was completed and
placed on production in November 2002.

CENTRAL AREA

The focus of our Central area is the Greater Bay Marchand area located in
state and federal waters off the coast of Louisiana approximately 60 miles south
of New Orleans in water depths of 60 feet or less and encompasses nearly 100
square miles. Also included in the Central area are two producing properties
acquired in the HHOC acquisition.

During 2002, we invested a total of $2.9 million in the Central area. Our
investments included the sidetracking of two wells, both of which were
successful, and the workover or recompletion of 7 wells, 6 of which were
successful. Production from this area accounted for approximately 25% of our net
daily production in 2002.

We acquired our interests in the Greater Bay Marchand area in several
separate transactions, the most significant of which follow:

SOUTH TIMBALIER 26

In June 1998, we purchased our initial 20% working interest in the South
Timbalier 26 field for approximately $9.0 million and assumed operatorship of
the field. In March 2000, we acquired our partner's 80% interest in the field,
and in April 2000, we sold 50% of our interest in the field. Our net cash
outflow related to these two transactions was $8.3 million. We continue to serve
as operator of the field with a 50% working interest.

BAY MARCHAND DRILL-TO-EARN AGREEMENTS

In August 1998, we entered into a drill-to-earn agreement with
ChevronTexaco Corporation ("ChevronTexaco") covering the federal outer
continental shelf acreage and in May 2000, expanded the coverage to include
ChevronTexaco's Louisiana state water-bottom acreage in the Bay Marchand field.
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. After the completion of the wells under this program,
ChevronTexaco serves as the operator.

We currently have an agreement with ChevronTexaco, which provides for a
five well drilling program and provides for a carry in favor of ChevronTexaco
through capital expenditures to establish first production. These operations
commenced in the fourth quarter of 2002 with the drilling, through sidetracks,
of two successful exploration wells. We acquired a 40% working interest in the
two wells we have drilled and intend to retain a similar interest in the three
remaining wells.

WESTERN AREA

In connection with the acquisition of HHOC, we added 10 producing fields
and one field under development to our property portfolio in our Western area.
The properties are all located in the Gulf of Mexico Shelf area in water depths
ranging from 20 to 476 feet. All of the properties that we acquired were
operated by HHOC, with working interests ranging from 25% to 100%. Subsequent to
the acquisition, we acquired two additional

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properties at the federal March lease sale and also acquired working interests
in several blocks through trades with industry partners bringing our total at
December 31, 2002 to 12 producing and five development fields.

During 2002 we invested a total of $47.1 million in the Western area. Our
investments included the drilling or sidetracking of 11 wells, 7 of which were
successful and the workover or recompletion of 6 wells, 5 of which were
successful. Production in this area accounted for approximately 23% of our net
daily production during 2002. The most significant exploration and development
operations undertaken in the Western Gulf of Mexico region during 2002 are
discussed below.

EUGENE ISLAND 247

Acquired as part of the HHOC transaction, one gas-discovery well on this
field was drilled prior to the acquisition in approximately 150 feet of water
and later completed and brought on-line in November 2002. At year-end, the well
was producing approximately 11.6 Mmcf per day. We are the operator of this
property and have a 98% working interest.

EUGENE ISLAND 27

Acquired at the March 2002 federal lease sale, we have drilled a successful
exploration well in approximately 20 feet of water. We are currently considering
development options with first production anticipated to occur in the third
quarter 2003. We are the operator of this property and have a 100% working
interest.

HIGH ISLAND A-538

Acquired as part of the HHOC transaction, a successful exploration well was
drilled in approximately 200 feet of water and was completed in 2002. Facilities
were installed and a development well was drilled and completed in January 2003.
Initial production commenced in February 2003. We are the operator of this
property with a 33% working interest.

HIGH ISLAND 72

Acquired as part of the HHOC transaction, this property had existing
production from the No. 1 well. We have drilled the No. 2 well in approximately
35 feet of water and had initial production in December 2002, however the well
is currently shut-in pending needed facility modifications with restored
production expected in the second quarter of 2003. We are the operator of this
field and have a 50% working interest in the No. 1 well and a 79% working
interest in the No. 2 well.

EAST CAMERON 9

Through two lease sales in 2001, we acquired 1,000 gross acres in East
Cameron 9. In January 2002, we announced a successful discovery well, drilled in
approximately 25 feet of water approximately 2.5 miles offshore in Cameron
Parish, Louisiana. The well was drilled to a total depth of 14,158 feet. We are
the operator of the well and own a 50% working interest. We achieved first
production in June 2002. Also in January 2002, we were the successful bidder on
a lease from the State of Louisiana on acreage that is contiguous to our
existing East Cameron acreage. The lease covers 229 gross acres and is in
approximately 25 feet of water.

SHIP SHOAL 133

We acquired an interest in this lease in 2002 and participated in the
drilling of the No. 1 well in approximately 50 feet of water. We have a 33%
working interest. The well was completed in the third quarter of 2002 and
production commenced in January of 2003.

WEST CAMERON 431

When acquired as part of the HHOC transaction, this property had an
existing dually-completed well. A successful exploration well, the No. 3 well,
was drilled and completed in approximately 100 feet of water and

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placed on production in December 2002. At year-end, this well was producing 5.6
Mmcf per day. We are the operator of the field and have a 70% working interest
in the first well and a 100% working interest in the new well.

WEST CAMERON 210

We obtained this lease through a partner and drilled a successful
exploratory well in approximately 55 feet of water. This well was completed in
November 2002 and is expected to begin production in the second quarter 2003. We
are the operator of the field and have a 50% working interest.

SOUTH MARSH ISLAND 24

We obtained a 25% working interest in this lease through a partner and
participated in the drilling of a successful exploratory well in approximately
80 feet of water in late 2002. This well will be completed and is expected to
begin production late in the second quarter 2003.

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 December 31, 2002, 2001 and
2000. The December 31, 2002 estimates of proved reserves are based on reserve
reports prepared by Netherland, Sewell & Associates, Inc. and Ryder Scott
Company, L.P., independent petroleum engineers, and the December 31, 2001 and
2000 estimates are based on a reserve report prepared by Netherland, Sewell &
Associates, Inc. Neither the present values, discounted at 10% per annum, of
estimated future net cash flows before income taxes, or the standardized measure
of discounted future net cash flows shown in the table are intended to represent
the current market value of the estimated oil and natural gas reserves we own.

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(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, 2002 amount was calculated using a period-end oil price of
$29.53 per barrel and a period-end natural gas price of $4.83 per Mcf, while
the December 31, 2001 amount was calculated using a period-end oil price of
$18.21 per barrel and a period-end natural gas price of $2.71 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) Net proved developed non-producing reserves as of December 31, 2002 were
9,916 Mbbls and 43,600 Mmcf.

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There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and in projecting future rates of production
and timing of development expenditures. For a discussion of these uncertainties,
see "Additional Factors Affecting Business."

COSTS INCURRED IN OIL AND NATURAL GAS ACTIVITIES

The following table sets forth certain information regarding the costs
incurred that are associated with finding, acquiring, and developing our proved
oil and natural gas reserves:

PRODUCTIVE WELLS

The following table sets forth the number of productive oil and natural gas
wells in which we owned an interest as of December 31, 2002:

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.
Twenty-nine gross oil wells and seventeen gross natural gas wells have dual
completions.

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ACREAGE

The following table sets forth information as of December 31, 2002 relating
to acreage held by us. Developed acreage is assigned to producing wells.

Leases covering 10% of our undeveloped net acreage will expire in 2003,
approximately 6% in 2004, 14% in 2005, 52% in 2006, and 18% in 2007.

WELL ACTIVITY

The following table shows our well activity for the years ended December
31, 2002, 2001 and 2000. 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.

Well activity refers to the number of wells completed at any time during
the fiscal years, regardless of when drilling was initiated. For the purpose of
this table, "completed" refers to the installation of permanent equipment for
the production of oil or natural gas.

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 interfere with the use of our
properties in the operation of our business.

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

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properties. We investigate title and generally 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.

REGULATORY MATTERS

REGULATION OF TRANSPORTATION AND SALE OF NATURAL GAS

Historically, the transportation and sale for resale of natural gas in
inter state commerce have been regulated pursuant to the Natural Gas Act of
1938, as amended ("NGA"), the Natural Gas Policy Act of 1978, as amended
("NGPA"), and regulations promulgated thereunder by the Federal Energy
Regulatory Commission ("FERC"). In the past, the federal government has
regulated the prices at which natural gas could be sold. While sales by
producers of natural gas can currently be made at uncontrolled market prices,
Congress could reenact price controls in the future. Deregulation of wellhead
natural gas sales began with the enactment of the NGPA. In 1989, Congress
enacted the Natural Gas Wellhead Decontrol Act, as amended (the "Decontrol
Act"). The Decontrol Act removed all NGA and NGPA price and non-price controls
affecting wellhead sales of natural gas effective January 1, 1993.

Since 1985, FERC has endeavored to make natural gas transportation more
accessible to natural gas buyers and sellers on an open and non-discriminatory
basis. 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
(collectively, "Order No. 636") to implement its open access policies. As a
result of the Order No. 636 program, the marketing and pricing of natural gas
have been significantly altered. The interstate pipelines' traditional role as
wholesalers of natural gas has been eliminated and replaced by a structure under
which pipelines provide transportation and storage service on an open access
basis to others who buy and sell natural gas. Although 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.

In 2000, FERC issued Order No. 637 and subsequent orders (collectively,
"Order No. 637"), which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things, Order No. 637
revised FERC pricing policy by waiving price ceilings for short-term released
capacity for a two-year experimental period, and effected changes in FERC
regulations relating to scheduling procedures, capacity segmentation, penalties,
rights of first refusal and information reporting. Most major aspects of Order
No. 637 have been upheld on judicial review, and most pipelines' tariff filings
to implement the requirements of Order No. 637 have been accepted by the FERC
and placed into effect.

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
transportation service. One of FERC's principal goals in carrying out OCSLA's
mandate is 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 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

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particular state will generally affect all intrastate natural gas shippers
within the state on a comparable basis, we believe that the regulation of
similarly situated intrastate natural gas transportation in any states in which
we operate and ship natural gas on an intrastate basis will not affect our
operations in any way that is of material difference from those of our
competitors.

REGULATION OF TRANSPORTATION OF OIL

Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at negotiated prices. 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. Effective January 1, 1995, FERC implemented
regulations establishing an indexing system (based on inflation) for
transportation rates for oil that allowed for an increase or decrease in the
cost of transporting oil to the purchaser. A review of these regulations by the
FERC in 2000 was successfully challenged on appeal by an association of oil
pipelines. On remand, the FERC in February 2003 increased the index slightly,
effective July 2001. 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
comparable shippers, we believe that the regulation of oil transportation rates
will not affect our operations in any way that is of material difference from
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.

Our subsidiary, EPL Pipeline, L.L.C., owns an approximately 12-mile oil
pipeline, which transports oil produced from South Timbalier 26 on the Gulf of
Mexico Shelf to Bayou Fourchon, Louisiana. Production transported on this
pipeline includes oil produced by us and our working interest partner in South
Timbalier 26. EPL Pipeline, L.L.C. has on file with the Louisiana Public Service
Commission and FERC tariffs for this transportation service and offers
non-discriminatory transportation for any willing shipper.

REGULATION OF PRODUCTION

The production of oil and natural gas is subject to regulation under a wide
range of local, 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 allowable rates of production from
oil and natural gas wells, the regulation of well spacing, and plugging and
abandonment of wells. Many states also restrict production to the market demand
for oil and natural gas, and several states have indicated 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 the 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 Minerals Management Service ("MMS") and are required to comply
with the regulations and orders promulgated by MMS under OCSLA. Among other
things, we are required to obtain prior MMS approval for any exploration plans
we pursue and our development and production plans for these leases. 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, MMS could require us to suspend or terminate our
operations on a federal lease.

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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
payments due under state oil and natural gas leases. The basis for royalty
payments established by MMS and the state regulatory authorities is generally
applicable to all federal and state 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. 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 protection of the environment, such as the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), the
Federal Water Pollution Control Act of 1972, as amended (the "Clean Water Act"),
and the Federal Clean Air Act, as amended (the "Clean Air Act"), 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 hydrocarbons and our use of facilities for treating, processing or
otherwise handling hydrocarbons and related wastes may be subject to regulation
under these and similar state legislation. These laws and regulations:

- restrict the types, quantities and concentration of various substances
that can be released into the environment in connection with drilling and
production activities;

- limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas; and

- impose substantial liabilities for pollution resulting from our
operations.

Failure to comply with these laws and regulations may result in the
assessment of administrative, civil and criminal fines and penalties or the
imposition of injunctive relief. Changes in environmental laws and regulations
occur regularly, and any changes that result in more stringent and costly waste
handling, storage, transport, disposal or cleanup requirements could materially
adversely affect our operations and financial position, as well as those in the
oil and natural gas industry in general. While we believe that we are in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements would not
have a material adverse impact on us, there is no assurance that this trend will
continue in the future.

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 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. 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 a disposal site and entities 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. It is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous

11

substances released into the environment. 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 properties that for many years have been used for
the exploration and production of oil and natural gas. Although we and our
predecessors have used 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.

At this time, we do not believe that we are associated with any Superfund
site and we have not been notified of any claim, liability or damages under
CERCLA.

Oil Pollution Act of 1990. The Oil Pollution Act of 1990, as amended (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 OPA is strict, and under certain circumstances 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 to
meet these obligations, which we believe is customary for comparable companies
in our industry. A failure to comply with 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 OPA, and we believe that compliance
with OPA's financial responsibility and other operating requirements will not
have a material adverse effect on us.

U.S. Environmental Protection Agency. U.S. Environmental Protection Agency
regulations address the disposal of oil and natural gas operational wastes under
three federal acts more fully discussed in the paragraphs that follow. The
Resource Conservation and Recovery Act of 1976, as amended ("RCRA"), provides a
framework for the safe disposal of discarded materials and the management of
solid and hazardous wastes. The direct disposal of operational wastes into
offshore waters is also limited under the authority of the Clean Water Act. When
injected underground, oil and natural gas wastes are regulated by the
Underground Injection Control program under Safe Drinking Water Act. If wastes
are classified as hazardous, they must be properly transported, using a uniform
hazardous waste manifest, documented, and disposed at an approved hazardous
waste facility. We have coverage under the Region VI National Production
Discharge Elimination System Permit for discharges associated with exploration
and development activities. We take the necessary steps to ensure all offshore
discharges associated with a proposed operation, including produced waters, will
be conducted in accordance with the permit.

Resource Conservation Recovery Act. RCRA, is the principal 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

12

or an "owner" or "operator" of a hazardous waste treatment, storage or disposal
facility. At present, RCRA includes a 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.

Clean Water Act. The Clean Water Act imposes restrictions and controls on
the discharge of produced waters and other wastes into navigable waters. Permits
must be obtained to discharge pollutants into state and federal waters and to
conduct construction activities in waters and wetlands. 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 waters.
Further, the EPA has adopted regulations requiring certain oil and natural gas
exploration and production facilities to obtain permits for storm water
discharges. Costs may be associated with the treatment of wastewater or
developing and implementing storm water pollution prevention plans. The Clean
Water Act and comparable state statutes provide for civil, criminal and
administrative penalties for unauthorized discharges for oil and other
pollutants and impose 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. 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.

Safe Drinking Water Act. Underground injection is the subsurface placement
of fluid through a well, such as the reinjection of brine produced and separated
from oil and natural gas production. The Safe Drinking Water Act of 1974, as
amended establishes 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 and
Texas, 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 the
requirements of applicable state underground injection control programs and our
permits.

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 gauges 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.

Marine Mammal and Endangered Species. Federal Lease Stipulations address
the reduction of potential taking of protected marine species (sea turtles,
marine mammals, Gulf Sturgen and other listed marine species). MMS permit
approvals will be conditioned on collection and removal of debris resulting from
activities related to exploration, development and production of offshore
leases. MMS has issued Notices to Lessees and Operators ("NTL") 2003-G06
advising of requirements for posting of signs in prominent places on all vessels
and structures and of an observing training program.

Consideration of Environmental Issues in Connection with Governmental
Approvals. Our operations frequently require licenses, permits and/or other
governmental approvals. Several federal statutes, including

13

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 may
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 and they qualify as a regulated hazardous
waste, this would 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 and MMS 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 emissions associated with offshore activities are
projected using a matrix and formula supplied by MMS, which has primacy from the
Environmental Protection Agency for regulating such emissions.

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 natural 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
material compliance with all applicable NORM standards established by the State
of Louisiana.

Abandonment Costs. One of the responsibilities of owning and operating oil
and natural gas properties is paying for the cost of abandonment. Effective
January 1, 2003, companies are required to reflect abandonment costs as a
liability on their balance sheets in the period in which it is incurred. We may
incur significant abandonment costs in the future which could adversely affect
our financial results.

ADDITIONAL FACTORS AFFECTING BUSINESS

EXPLORATION AND DRILLING RISKS

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. Our cost of drilling, completing and operating wells is often
uncertain before drilling commences. Overruns in budgeted expenditures are
common risks that can

14

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;

- 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.

LIABILITY RISKS

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, such as stuck oil field drilling and service
tools and casing collapse;

- fires and explosions;

- personal injuries and death; and

- natural disasters.

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.

VOLATILITY OF OIL AND NATURAL GAS PRICES

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 the global supply, demand and inventories of oil;

- domestic natural gas supply, demand and inventories;

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

- the price and quantity of foreign imports of oil;

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

15

- economic and energy infrastructure disruptions caused by actual or
threatened acts of war, or terrorist activities, or national security
measures deployed to protect the United States from such actual or
threatened acts or activities;

- economic stability of major oil and natural gas companies and the
interdependence of oil and natural gas and energy trading companies;

- the level of worldwide oil and natural gas exploration and production
activity;

- weather conditions;

- technological advances affecting energy consumption; and

- the price and availability of alternative fuels.

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.

UNCERTAINTY OF ESTIMATES OF OIL AND NATURAL GAS 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 Report.

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.

It cannot be assumed that the present value of future net revenues from our
proved reserves referred to in this Report, is the current market value of our
estimated oil and natural gas reserves. In accordance with SEC requirements, we
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.

MARKETABILITY OF 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 oil or 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.

OUR LIMITED OPERATING HISTORY

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 also

16

completed two acquisitions in 2000 and the acquisition of HHOC in January 2002,
which have changed our company.

A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
IN ONE PROPERTY

During the month of December 2002, 57% of our net 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 December 31, 2002, approximately 58% of our proved reserves
were 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.

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

Producing oil and natural gas reservoirs generally are characterized by
declining production rates that vary depending upon reservoir characteristics
and other factors. High production rates generally result in recovery of a
relatively higher percentage of reserves from properties during the initial few
years of production. All of our operations are on the Gulf of Mexico Shelf.
Production from reserves in reservoirs in the Gulf of Mexico generally declines
more rapidly than from reservoirs in many other producing regions of the world.
As a result, our reserve replacement needs from new investments are relatively
greater. 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.

RAPID GROWTH MAY PLACE SIGNIFICANT DEMANDS ON OUR RESOURCES

We have experienced rapid growth in our operations and expect that
expansion of our operations will continue. Our acquisition of HHOC generated
most of our growth in 2002. 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;

- complexities in integrating acquired businesses and personnel;

- the need to train and manage our 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 these demands or if our systems, procedures or controls are not adequate to
support our operations, our business could be harmed.

ACQUISITION OF ADDITIONAL RESERVES

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.

17

Our assessments will not reveal all existing or potential problems, nor
will they permit us to become familiar enough with the properties to evaluate
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 conducted. 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.

CAPITAL REQUIREMENTS

In order to finance acquisitions of additional producing properties,
finance the development of any discoveries made through any expanded exploratory
program that might be undertaken 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.

CONTROL BY PRINCIPAL STOCKHOLDER

Our principal stockholder, Evercore Capital Partners L.P., together with
its affiliates ("Evercore"), beneficially owns approximately 34% of our
outstanding shares of common stock and Evercore is entitled to nominate four of
our nine directors. Evercore's approval 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. 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.

AVAILABILITY AND COSTS OF RESOURCES

All of our operations are on 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. Periodically, drilling activity in the Gulf of Mexico has increased,
and we have experienced 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 offer
assurance that costs will not increase again or that necessary equipment and
services will be available to us at economical prices.

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 approval of common
stockholders; 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.

18

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.

RELIANCE ON KEY PERSONNEL

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 Shelf area is highly competitive, and our success there
will depend largely on our ability to attract and retain experienced
geoscientists and other professional staff.

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 make assurances 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.

SIGNIFICANT CUSTOMERS

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
Shell Trading (US) Company ("Shell") expiring December 2003, and Evergreen
thereafter unless either party cancels the contract. 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
ChevronTexaco and Shell. Currently, our most significant purchaser of our
natural gas production is Duke Energy Trading and Marketing, L.L.C. ("Duke"). 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 a natural gas
processing arrangement for our production at our Bay Marchand and East Bay
fields with Dynegy Midstream Services, L.P. Of our total oil and natural gas
revenues in 2002, Shell accounted for approximately 41 percent, Duke 27 percent
and ChevronTexaco 11 percent.

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 although a temporary
disruption in production revenues could occur.

EMPLOYEES

As of December 31, 2002, we had 132 full-time employees, including 47
geoscientists, engineers and technicians and 57 field personnel. Our employees
are not represented by any labor union. We consider relations with our employees
to be satisfactory and we have never experienced a work stoppage or strike.

ITEM 3. LEGAL PROCEEDINGS

In the ordinary course of business, we are a defendant in various legal
proceedings. We do not expect our exposure in these proceedings, individually or
in the aggregate, to have a material adverse effect on our financial position,
results of operations or liquidity.

19

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

None

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information regarding our executive
officers:

Richard A. Bachmann has been president and chief executive officer and
chairman of the board of directors since our incorporation in January 1998. Mr.
Bachmann began organizing our company in February 1997. From 1995 to January
1997, he served as director, president and chief operating officer of LL&E, an
independent oil and gas exploration company. From 1982 to 1995, Mr. Bachmann
held various positions with LL&E, including director, executive vice president,
chief financial officer and senior vice president of finance and administration.
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. He is also a director of Superior
Energy Services, Inc.

Gary L. Hall joined us in January 2002, following the closing of the HHOC
acquisition, as vice chairman and a member of our board of directors. Prior to
joining us, Mr. Hall had been chairman of the board of directors and chief
executive officer of HHOC since it began operations in 1983. He has been
involved in the oil and gas exploration and production business in the Gulf of
Mexico since 1976, serving in various positions with major integrated and
independent energy companies including Mobil Oil Company and Pogo Producing
Company.

Suzanne V. Baer joined us in April 2000 as vice president and chief
financial officer and was promoted to executive vice president in May 2001. Ms.
Baer has 33 years of financial management, investor relations and treasury
experience in the energy industry. From July 1998 until March 2000, Ms. Baer had
been 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 overseeing
various operating activities and was promoted to executive vice president and
chief operating officer in May 2001. Mr. Coldren has 26 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.

John H. Peper joined us in January 2002, following the closing of the HHOC
acquisition, as executive vice president, general counsel and corporate
secretary. Prior to joining us, Mr. Peper had been senior vice president,
general counsel and secretary of HHOC since February 1993. Mr. Peper also served
as a director of HHOC since October 1991. For more than five years prior to
joining HHOC, Mr. Peper was a partner in the law firm of Jackson Walker, L.L.P.,
where he continued to serve in an of counsel capacity through 2001.

20

Bruce R. Sidner joined us in January 2002, following the closing of the
HHOC acquisition, as executive vice president of exploration. Prior to joining
us, Mr. Sidner had been vice-president, exploration, of HHOC since February
1984. Mr. Sidner also served as a director of HHOC since 1990. For the seven
years prior to joining HHOC, Mr. Sidner served in various positions with major
integrated and independent energy companies including Exxon Production Research
and Pogo Producing Company.

PART II

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

Our common stock is listed on the New York Stock Exchange under the symbol
"EPL." The following table sets forth, for the periods indicated, the range of
the high and low sales prices of our common stock as reported by the New York
Stock Exchange.

On February 28, 2003, the last reported sale price of our common stock on
the New York Stock Exchange was $10.80 per share.

As of February 28, 2003, there were approximately 158 holders of record of
our common stock.

We have not paid any cash dividends in the past on our common stock and do
not intend to pay cash dividends on our common stock in the foreseeable future.
We intend to retain earnings for the future operation and development of our
business. Any future cash dividends to holders of common stock would depend on
future earnings, capital requirements, our financial condition and other factors
determined by our board of directors.

21

ITEM 6. SELECTED FINANCIAL DATA

The following table shows selected consolidated financial data derived from
our consolidated financial statements which are set forth in Item 8 of this
Report. The data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" in Item 7 of this
Report.

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

(1) The 2000 loss from operations includes a one time non-cash stock
compensation charge for shares released from escrow to management and
director stockholders of $38.2 million and a non-cash charge of $2.1 million
for bonus shares awarded to employees at the time of the initial public
offering. The after-tax amount of these charges totaled $39.5 million.
Although these charges reduced our net income, they increased
paid-in-capital and thus did not result in a net reduction of total
stockholders' equity.

(2) Net loss available to common stockholders is computed by subtracting
preferred stock dividends and accretion of discount of $3.3 million from net
loss for the year ended December 31, 2002 and by subtracting preferred stock
dividends and accretion of issuance costs of $6.7 million and $0.8 million
for the years ended December 31, 2000 and 1999, respectively.

22

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

OVERVIEW

We are an independent oil and natural gas exploration and production
company, incorporated in January 1998, with operations concentrated in the
shallow to moderate depth waters of the Gulf of Mexico Shelf.

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

On March 31, 2000, we acquired the 80% working interest in South Timbalier
26 that we did not previously own and subsequently, on April 20, 2000, sold 50%
of our working interest in South Timbalier 26. On March 31, 2000, we closed the
purchase of an average 96.1% working interest in the East Bay field and in
September 2000, we closed the acquisition of a 14.5% working interest in South
Timbalier 22, 23 and 27.

On January 15, 2002, we acquired HHOC for consideration of $88.3 million
and the assumption of HHOC's working capital deficit. The consideration included
the issuance of $38.4 million of 11% Senior Subordinated Notes due 2009. We also
issued Series D Exchangeable Convertible Preferred Stock with a fair value at
the issue date of $34.7 million ($38.4 million face amount) with an effective
dividend rate of 10%. The acquisition moved our operations to a more balanced
oil and natural gas reserves and production profile and reduced our production
exposure to any particular field. Through the acquisition we added 59.1 Bcfe of
proved reserves in January 2002, 98% of which were natural gas. The acquisition
also included 10 producing properties and 12 offshore exploratory blocks.

We have included the results of operations from the East Bay and South
Timbalier 26 acquisitions from the closing date of March 31, 2000, the South
Timbalier 22, 23 and 27 from the closing date of September 7, 2000 and the HHOC
acquisition from the closing date of January 15, 2002. These acquisitions have
significantly affected our results of operations and production growth.

For the foregoing reasons, the East Bay, South Timbalier 26, South
Timbalier 22, 23 and 27 and HHOC acquisitions will affect the comparability of
our historical results of operations with results of operations from year to
year.

On November 1, 2000, we consummated our initial public offering of 5.75
million shares of common stock. After payment of underwriting discounts and
commissions, we received net proceeds of $80.2 million on November 7, 2000. With
the proceeds, we retired outstanding debt of $73.9 million and paid
approximately $5.1 million to redeem outstanding Series C Preferred Stock.

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. See "Additional Factors Affecting Business" in Items 1
and 2 for a more detailed discussion of these risks.

23

RESULTS OF OPERATIONS

The following table presents information about our oil and natural gas
operations.

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

(1) Net of the effect of hedging transactions.

PRODUCTION

Crude Oil and Condensate. Our net oil production for 2002 decreased to
8,148 Bbls per day from 10,358 Bbls per day in 2001. The decrease is the result
of fewer workovers/recompletions on oil wells in 2002 combined with the impact
of tropical weather in the Gulf of Mexico and natural reservoir declines.

Our net oil production for 2001 increased to 10,358 Bbls per day from 7,622
Bbls per day in 2000. The increase was the result of 33 successful oil well
operations, which commenced production in 2001 combined with a full year of
production from the acquisitions we made in 2000, and was partially offset by
natural declines from other producing wells.

Natural Gas. Our net natural gas production for 2002 increased to 54,150
Mcf per day from 34,562 Mcf per day in 2001. The increase is the result of
natural gas volumes added in the acquisition of HHOC combined with new
production from natural gas wells completed during the year and was partially
offset by tropical weather in the Gulf of Mexico and natural reservoir declines.

Our net natural gas production for 2001 increased to 34,562 Mcf per day
from 15,781 Mcf per day in 2000. The increase was the result of 43 successful
natural gas well operations which commenced production in 2001 combined with a
full year of production from the acquisitions we made in 2000, and was partially
offset by natural declines from other producing wells.

REALIZED PRICES

Crude Oil and Condensate. Our average realized oil price in 2002 was
$23.64 per Bbl, consistent with the average realized price of $23.44 per Bbl in
2001. Hedging activities in 2002 reduced oil price realizations by $0.51 per Bbl
or 2% from the $24.15 per Bbl that would have otherwise been received. In 2001,
hedging activities reduced oil price realizations by $1.10 per Bbl or 4% from
the $24.54 per Bbl that would have otherwise been received.

24

Our average realized oil price in 2001 was $23.44 per Bbl, a decrease of 9%
from an average realized price of $25.86 per Bbl in 2000. Hedging activities in
2001 reduced oil price realizations by $1.10 per Bbl or 4% from the $24.54 per
Bbl that would have otherwise been received. In 2000, hedging activities reduced
oil price realizations by $3.80 per Bbl or 13% from the $29.66 per Bbl that
would have otherwise been received.

Natural Gas. Our average realized natural gas price in 2002 was $3.23 per
Mcf, a significant decrease of 27% from an average realized price of $4.40 per
Mcf in 2001. Hedging activities in 2002 reduced natural gas realizations by
$0.18 per Mcf from the $3.41 per Mcf that would have otherwise been received.
Hedging activities in 2001 increased natural gas realizations by $0.05 per Mcf
from the $4.35 per Mcf that would have otherwise been received.

Our average realized natural gas price in 2001 was $4.40 per Mcf, a
decrease of 12% from an average realized price of $4.98 per Mcf in 2000. Hedging
activities in 2001 increased natural gas realizations by $0.05 per Mcf from the
$4.35 per Mcf that would have otherwise been received. We did not have hedging
positions for natural gas related to 2000 production.

REVENUES AND NET INCOME

Our oil and natural gas revenues decreased to $134.1 million in 2002 from
$144.1 million in 2001. Although production volumes increased 7% on a barrel of
oil equivalent basis, the 27% decline in natural gas price realizations more
than offset this benefit and resulted in lower revenues.

Our oil and natural gas revenues increased to $144.1 million in 2001 from
$100.9 million in 2000. The increase in revenues was primarily due to higher
production volumes reflecting a full year of production from the acquisitions in
2000 combined with current year drilling activities. The impact of these
increases was partially offset by lower commodity prices.

We recognized a net loss of $8.8 million in 2002 compared to net income of
$12.0 million in 2001. The decrease in net income was primarily due to the
decrease in oil and natural gas revenues previously discussed, combined with
higher depletion, depreciation and amortization expense incurred primarily as a
result of the HHOC acquisition. We recognized net income of $12.0 million in
2001 compared to a loss of $18.7 million in 2000. The following items had a
significant impact on our net income or loss in 2002, 2001 and 2000 and effect
the comparability of the results of operations for those years:

- In March 2002, in connection with management's plan to reduce costs and
effectively combine the operations of HHOC with ours, we executed a
severance plan and recorded an expense of $1.2 million.

- In December 2001, we purchased a financially-settled put swaption (the
"put swaption"), which provided us with a financially-settled natural gas
swap at $2.95 per Mmbtu for 30,000 Mmbtu per day for the period from
February 2002 through January 2003. The put swaption also provided us the
option to cancel the swap on January 15, 2002. In the fourth quarter of
2001, we recognized an expense of $1.9 million, related to the change in
time value of the option portion of the contract compared to $0.5 million
expensed in January 2002 related to the remaining change in time value.
This expense is classified as other revenue in the consolidated
statements of operations in 2002 and 2001.

- We recorded business interruption income of $3.5 million in 2001 compared
to $1.8 million in 2000 as a result of the rupture of a high-pressure
natural gas transfer line at our East Bay field. The rupture occurred in
November 2000 and the transfer line was restored to service in February
2001. This income is classified as other revenue in the consolidated
statements of operations in 2001 and 2000.

- The net loss in 2000 is attributed to one-time non-cash stock
compensation charges related to the initial public offering. We
recognized charges of $38.2 million related to the release to management
and director stockholders of shares placed in escrow in 1999 and $2.1
million related to bonus shares awarded to employees. After tax, these
charges totaled $39.5 million. Although these charges reduced our net
income, they increased paid-in-capital and thus did not result in a net
reduction of total stockholders' equity. Excluding the effect of the
charges, we had net income of $20.8 million in 2000.

25

OPERATING EXPENSES

Operating expenses were impacted by the following:

- Lease operating expense decreased $2.1 million to $34.4 million in 2002.
The decrease is attributable to the concerted effort to reduce operating
costs, primarily at our East Bay field, which more than offset additional
costs from the HHOC properties.

Lease operating expense increased $12.3 million to $36.5 million in 2001.
The increase was primarily attributable to a full year of operations from
the acquisitions we made in 2000.

- Taxes, other than on earnings decreased $0.6 million to $6.6 million in
2002. This reduction was due to the decrease in the production volumes
and prices received for our oil production on state leases subject to
Louisiana severance taxes.

Taxes, other than on earnings increased $0.9 million to $7.2 million in
2001. The increase in production taxes are primarily attributable to a
full year of production from the acquisition of the East Bay field where
a portion of the production is subject to Louisiana severance taxes and
property taxes.

- Exploration expenditures decreased $4.4 million to $10.7 million in 2002.
The expense in 2002 is primarily the result of an increase in seismic
expenditures and delay rentals to $4.8 million and a decrease in dry hole
charges to $5.9 million as a result of exploratory wells drilled during
the year, which were found to be not commercially productive.

Exploration expenditures increased $13.4 million to $15.1 million in
2001. The expense in 2001 is primarily the result of seismic expenditures
and delay rentals of $1.5 million and dry hole charges of $13.6 million
as a result of our increased exploration program in 2001.

- Depreciation, depletion and amortization increased $17.6 million to $64.5
million in 2002. The increase was due to the increased depreciable asset
base resulting from the acquisition of HHOC and drilling activities
subsequent to December 31, 2001, increased production volumes,
amortization of unproved leases awarded at the March 2002 lease sale and
acquired with HHOC and downward reserve revisions due to prices at
December 31, 2001. This expense includes $6.8 million for the accrual of
abandonment liabilities as compared to $8.1 million in 2001.

Depreciation, depletion and amortization increased $21.3 million to $46.9
million in 2001. This expense includes $8.1 million for the accrual of
abandonment liabilities compared to $5.8 million in 2000. The overall
increase was primarily due to increased production volumes and an
increased depreciable asset base resulting primarily from development
activities.

- Other general and administrative expenses increased $4.3 million to $22.5
million in 2002. The increase was primarily due to a litigation
settlement ($2.0 million), increased insurance costs ($0.9 million),
increased rent and other office costs ($1.0 million) and other costs
associated with the combination of HHOC's operations with ours primarily
in the first quarter of 2002 as we assimilated HHOC.

Other general and administrative expenses increased $7.1 million to $18.2
million in 2001. The increase was primarily due to the hiring of
additional personnel ($2.3 million), increased consultant fees ($0.7
million), increased insurance costs ($1.6 million), increased information
technology costs ($0.7 million), $0.3 million to fully reserve our hedge
contract receivable from Enron and other costs associated with our
increased operations.

- Non-cash stock-based compensation expense of $0.5 million was recognized
in 2002, a decrease of $1.2 million from 2001. This expense relates to
restricted stock and stock option grants made to employees.

Non-cash stock-based compensation expense of $1.7 million was recognized
in 2001, a decrease of $1.1 million from 2000. This expense relates to
restricted stock and stock option grants made to employees.

26

OTHER INCOME AND EXPENSE

Interest. Interest expense increased $5.1 million to $7.0 million in 2002.
The increase was a result of increased borrowings under our bank facility and
the issuance of the Notes on January 15, 2002 related to the acquisition of
HHOC.

Interest expense decreased $5.5 million to $1.9 million in 2001. The
decrease is a result of lower interest rates and the repayment of borrowings
under our bank credit facility, which had been drawn for the acquisitions
completed on March 31, 2000.

Gain on Sale of Oil and Gas Assets. On April 20, 2000, we sold 50% of our
working interest in the South Timbalier 26 field, resulting in a gain of
approximately $7.8 million.

LIQUIDITY AND CAPITAL RESOURCES

The decline in revenues we experienced in 2002 in combination with the
assumption of HHOC's working capital deficit significantly reduced our cash
flows from operations during 2002. Cash flows from operating activities totaled
$25.4 million in 2002. Our future cash flows from operations before changes in
working capital will depend on our ability to maintain and increase production
through our development and exploratory drilling program, as well as the prices
of oil and natural gas.

Net cash of $54.4 million used in investing activities in 2002 primarily
included the $10.7 million of cash paid in conjunction with the acquisition of
HHOC, which is net of $1.9 million in cash received, oil and natural gas
property capital and exploration expenditures of $43.0 million and lease
acquisitions of $1.9 million. Exploration expenditures incurred are excluded
from operating cash flows and included in investing activities. During 2002, we
completed 17 drilling projects and 27 recompletion/workover projects, 34 of
which were successful. During 2001, we completed 22 drilling projects and 66
recompletion/workover projects, 76 of which were successful.

We financed the amount by which our capital expenditures exceeded cash
flows from operations by increasing our borrowings against our bank credit
facility. Our bank credit facility, as amended on November 1, 2002, consists of
a revolving line of credit with a group of banks available through March 30,
2005 (the "bank facility"). The bank facility currently has a borrowing base of
$100 million that is subject to redetermination based on the proved reserves of
the oil and natural gas properties that serve as collateral for the bank
facility as set out in the reserve report delivered to the banks each April 1
and October 1. The bank facility permits both prime rate based borrowings and
London interbank offered rate ("LIBOR") borrowings plus a floating spread. The
spread will float up or down based on our utilization of the bank facility. The
spread can range from 1.50% to 2.25% above LIBOR and 0% to 0.75% above prime.
The borrowing base under the bank facility is secured by substantially all of
our assets. The bank facility contains customary events of default and requires
that we satisfy various financial covenants. At February 28, 2003, we had $80
million outstanding and $20 million of credit capacity available under the bank
facility. Also included in long-term debt in the consolidated balance sheet is
$38.4 million of the Notes, which are due January 2009.

We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active capital expenditure
program. We believe that cash flows from operations before changes in working
capital will be sufficient to meet our capital requirements for at least the
next twelve months and reduce borrowings under our bank facility to levels in
effect at year end 2002. Availability under the bank facility will be used to
balance short-term fluctuations in working capital requirements. However,
additional financing may be required in the future to fund our growth.

Our 2003 capital expenditure budget is focused on exploration, exploitation
and development activities on our proved properties combined with moderate and
higher risk exploratory activities on undeveloped leases. We currently intend to
allocate approximately 65% of our budget on an annual basis on low risk
development and exploitation activities, approximately 25% to moderate risk
exploration opportunities and approximately 10% to higher risk, higher potential
exploration opportunities. Our capital expenditure budget for 2003 is currently
approximately $90 million. The level of our capital expenditure budget is based
on many factors, including results of our drilling program, oil and natural gas
prices, industry conditions, participation by other working interest

27

owners and the costs of drilling rigs and other oilfield goods and services.
Should actual conditions differ materially from expectations, some projects may
be accelerated or deferred and, consequently, may increase or decrease total
2003 capital expenditures.

LONG-TERM DEBT AND LEASE OBLIGATIONS

The following summarizes our obligations under long-term debt and operating
lease obligations as of December 31, 2002:

HEDGING ACTIVITIES

We enter into hedging transactions with major financial institutions to
reduce exposure to fluctuations in the price of oil and natural gas. We also
distribute our hedging transactions to a variety of financial institutions to
reduce our exposure to counterparty credit risk. Our hedging program uses
financially-settled crude oil and natural gas swaps, zero-cost collars and a
combination of options used to provide floor prices with varying upside price
participation. Our hedges are benchmarked to the New York Mercantile Exchange
("NYMEX") West Texas Intermediate crude oil contract and Henry Hub natural gas
contracts. With a financially-settled swap, 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. With a zero-cost collar, the counterparty is
required to make a payment to us if the settlement price for any settlement
period is below the floor price of the collar, and we are required to make a
payment to the counterparty if the settlement price for any settlement period is
above the cap price of the collar. In some hedges, we have modified our collar
to provide full upside participation after a limited non-participation range. We
had the following contracts as of December 31, 2002:

28

Subsequent to December 31, 2002 we entered into the following contracts:

On January 1, 2001, we adopted Statement of Financial Accounting Standards
No. 133 ("Statement 133"), as amended, Accounting for Derivative Instruments and
Hedging Activities. Statement 133 establishes accounting and reporting standards
requiring that derivative instruments, including certain derivative instruments
embedded in other contracts, be recorded at fair market value and included as
either assets or liabilities in the balance sheet. The accounting for changes in
fair value depends on the intended use of the derivative and the resulting
designation, which is established at the inception of the derivative. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the statement of operations. For
derivative instruments designated as cash-flow hedges, changes in fair value, to
the extent the hedge is effective, will be recognized in other comprehensive
income (a component of stockholders' equity) until settled, when the resulting
gains and losses will be recorded in earnings. Hedge ineffectiveness is measured
at least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time. Any change in fair value
resulting from ineffectiveness, as defined by Statement 133, is charged
currently to earnings.

Our hedged volume as of December 31, 2002 approximated 26% of our estimated
production from proved reserves through the balance of the terms of the
contracts.

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.

CRITICAL ACCOUNTING POLICIES

In preparing our financial statements in accordance with accounting
principles generally accepted in the United States, management must make a
number of estimates and assumptions related to the reporting of assets,
liabilities, revenues, and expenses and the disclosure of contingent assets and
liabilities. Application of certain of our accounting policies requires a
significant number of estimates. These accounting policies are described below.

- Successful efforts method -- We utilize the successful efforts method to
account for exploration and development expenditures. Successful
exploratory drilling costs and all development capital expenditures are
capitalized and systematically charged to expense using the units of
production method based on proved developed oil and natural gas reserves
as estimated by our internal engineers and independent petroleum
engineers. We also use proved developed reserves to recognize expense for
future estimated dismantlement and abandonment costs. Although the
engineers are knowledgeable of and follow the guidelines for reserves as
established by the U.S. Securities and Exchange Commission, the
estimation of

29

reserves requires the engineers to make a significant number of
assumptions based on professional judgment. Estimated reserves are,
therefore, often subject to future revision, certain of which could be
substantial, based on the availability of additional information,
including: reservoir performance, new geological and geophysical data,
additional drilling, technological advancements, price changes and other
economic factors. Changes in oil and natural gas prices can lead to a
decision to start-up or shut-in production, which can lead to revisions
to reserve quantities. Reserve revisions inherently lead to adjustments
of depreciation rates utilized by us. We cannot predict the types of
reserve revisions that will be required in future periods.

- Impairment of properties -- We continually monitor our long-lived assets
recorded in property and equipment in our consolidated balance sheet to
make sure that they are fairly presented. We must evaluate our properties
for potential impairment when circumstances indicate that the carrying
value of an asset could exceed its fair value. A significant amount of
judgment is involved in performing these evaluations since the results
are based on estimated future events. Such events include a projection of
future oil and natural gas sales prices, an estimate of the ultimate
amount of recoverable oil and natural gas reserves that will be produced
from a field, the timing of this future production, future costs to
produce the oil and natural gas, and future inflation levels. The need to
test a property for impairment can be based on several factors, including
a significant reduction in sales prices for oil and/or natural gas,
unfavorable adjustments to reserves, or other changes to contracts,
environmental regulations or tax laws. All of these factors must be
considered when testing a property's carrying value for impairment. We
cannot predict the need for, nor estimate the amount of, impairment
charges that may be recorded in the future.

- Derivative instruments and hedging activities -- We enter into hedging
transactions for our oil and natural gas production to reduce our
exposure to fluctuations in the price of oil and natural gas. Our hedging
transactions have to date consisted primarily of financially-settled
swaps and zero-cost collars and combination options with major financial
institutions. 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. Under the provisions of Statement 133, we
are required to record our derivative instruments at fair market value as
either assets or liabilities in our consolidated balance sheet. The fair
value recorded is an estimate based on future commodity prices available
at the time of the calculation. The fair market value could differ from
actual settlements if 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.

NEW ACCOUNTING POLICIES

In 2001, the Financial Accounting Standards Board ("FASB") issued Statement
143, Accounting for Asset Retirement Obligations ("Statement 143"). Statement
143 requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred, a corresponding
increase in the carrying amount of the related long-lived asset and is effective
for fiscal years beginning after June 15, 2002. We will adopt Statement 143
effective January 1, 2003, using the cumulative effect approach to recognize
transition amounts for asset retirement obligations, asset retirement costs and
accumulated depreciation. We currently record estimated costs of dismantlement,
removal, site restoration and similar activities as part of our depreciation,
depletion and amortization for oil and gas properties and record a separate
liability for such amounts in other liabilities. The effect of Statement 143 on
our results of operations and financial condition at adoption is expected to
include a net increase in long-term liabilities of $14.2 million; an increase in
net property, plant and equipment of $17.8 million; a cumulative effect of
adoption income of $2.3 million net of deferred income taxes and a deferred tax
liability of $1.3 million. Subsequent to adoption, we do not expect this
standard to have a material impact on our financial position or our results of
operations.

During the second quarter of 2002, the FASB issued Statement 145,
Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13 and Technical Corrections ("Statement 145"). This statement rescinds SFAS No.
4, Reporting Gains and Losses from Extinguishments of Debt, and requires that
all gains and losses from extinguishments of debt should be classified as
extraordinary items only if they meet the criteria of in APB No. 30. Applying
APB No. 30 will distinguish transactions that are part of an entity's recurring
operations

30

from those that are unusual or infrequent or that meet the criteria for
classification as an extraordinary item. Any gain or loss on extinguishment of
debt that was classified as an extraordinary item in prior periods presented
that does not meet the criteria in APB No. 30 for classification as an
extraordinary item must be reclassified. We will adopt the provisions related to
the rescission of SFAS No. 4 as of January 1, 2003. The adoption of Statement
145 is not expected to have an impact on our results of operations or financial
position.

In June 2002, the FASB issued Statement 146, Accounting for Costs
Associated with Exit or Disposal Activities ("Statement 146"). Statement 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and requires that liabilities associated with these costs be
recorded at their fair value in the period in which the liability is incurred.
Statement 146 will be effective for disposal activities initiated after December
31, 2002. We will adopt the provisions related to Statement 146 as of January 1,
2003; however, the adoption is not expected to have an impact on our results of
operations or financial position.

In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 requires a company to
recognize a liability for the obligations it has undertaken in issuing a
guarantee. This liability would be recorded at the inception of a guarantee and
would be measured at fair value. The measurement provisions of this statement
apply prospectively to guarantees issued or modified after December 31, 2002.
The disclosure provisions apply to financial statements for periods ending after
December 15, 2002. We do not currently have guarantees that require disclosure.
We will adopt the measurement provisions of this statement in the first quarter
of 2003 and the adoption is not expected to have a material effect on our
financial position or results of operations.

In December 2002, the FASB issued Statement 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure ("Statement 148"). Statement 148
provides alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, Statement 148 amends the disclosure requirements of Statement 123,
"Accounting for Stock-Based Compensation," to require more prominent and
frequent disclosures in financial statements about the effects of stock-based
compensation. The transition guidance and annual disclosure provisions of
Statement 148 are effective for fiscal years ending after December 15, 2002,
while the interim disclosure provisions are effective for periods beginning
after December 15, 2002. We are currently assessing the impact of the transition
options presented in Statement 148 and adoption of the disclosure provisions
required by Statement 148 are included in this Report on Form 10-K.

In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"). FIN 46 requires a company to
consolidated a variable interest entity if it is designated as the primary
beneficiary of that entity even if the company does not have a majority of
voting interest. A variable interest entity is generally defined as a entity
where its equity is unable to finance its activities or where the owners of the
entity lack the risk and rewards of ownership. The provisions of FIN 46 apply
immediately to variable interest entities created after January 31, 2003 and to
variable interest entities in which an enterprise obtains an interest after that
date. The adoption of FIN 46 is not currently expected to have an effect on our
financial position or results of operations when adopted.

ITEM 7A. 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 our bank facility. Under our current policies, we
do not use interest rate derivative instruments to manage exposure to interest
rate changes. At December 31, 2002, $65 million of our long-term debt had
variable interest rates, while the remaining long-term debt had fixed interest
rates. If market interest rates average 1% higher or lower in 2003 than in 2002,
interest expense on variable rate debt would increase (decrease), and loss
before income taxes would increase (decrease) by approximately $0.7 million
based on the total variable rate debt outstanding at December 31, 2002.

31

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 bank facility 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.

We use derivative commodity instruments to manage commodity price risks
associated with future oil and natural gas production. As of December 31, 2002,
we had the following contracts in place:

Subsequent to December 31, 2002 we entered into the following contracts:

Our hedged volume as of December 31, 2002 approximated 26% of our estimated
production from proved reserves through the balance of the terms of the
contracts. Had these contracts been terminated at December 31, 2002, we estimate
the loss would have been $3.4 million.

We use a sensitivity analysis technique to evaluate the hypothetical effect
that changes in the market value of crude oil and natural gas may have on fair
value of our derivative instruments. At December 31, 2002, the potential change
in the fair value of commodity derivative instruments assuming a 10% adverse
movement in the underlying commodity price was a $4.1 million increase in the
combined estimated loss.

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.

32

GLOSSARY OF OIL AND NATURAL GAS TERMS

"3-D" or "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
Report in reference to oil and other liquid hydrocarbons.

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

"Bcf" One billion cubic feet.

"Bcfe" One billion cubic feet equivalent, with one barrel of oil being
equivalent to six thousand cubic feet of natural gas.

"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.

"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.

"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.

33

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF MANAGEMENT

The consolidated financial statements of Energy Partners, Ltd. and
subsidiaries and the related information included in this Report have been
prepared by management in conformity with accounting principles generally
accepted in the United States of America. The financial statements include
amounts that are management's best estimates and judgments.

Management maintains a system of internal controls including internal
accounting controls that provide management with reasonable assurance that our
assets are protected and that published financial statements are reliable and
free of material misstatement. Management is responsible for the effectiveness
of internal controls. This is accomplished through established codes of conduct,
accounting and other control systems, policies and procedures, employee
selection and training, appropriate delegation of authority and segregation of
responsibilities.

The Audit Committee of the Board of Directors, composed solely of directors
who are not officers or employees of the Company, meets regularly with the
independent certified public accountants, financial management and counsel. To
ensure complete independence, the certified public accountants have full and
free access to the Audit Committee to discuss the results of their audits, the
adequacy of internal controls and the quality of financial reporting.

Our independent certified public accountants provide an objective
independent review by their audit of the Company's financial statements. Their
audit is conducted in accordance with generally accepted auditing standards and
includes a review of internal accounting controls to the extent deemed necessary
for the purposes of their audit.

/s/ RICHARD A. BACHMANN /s/ SUZANNE V. BAER
Richard A. Bachmann Suzanne V. Baer
Chairman, President and Executive Vice President
Chief Executive Officer and Chief Financial Officer

34

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Energy Partners, Ltd.:

We have audited the accompanying consolidated balance sheets of Energy
Partners, Ltd. and subsidiaries as of December 31, 2002 and 2001, and the
related consolidated statements of operations, changes in stockholders' equity,
and cash flows for each of the years in the three-year period ended December 31,
2002. 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 auditing standards generally
accepted in the United States of America. 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Energy
Partners, Ltd. and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.

As discussed in note 2 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and hedging
activities in 2001.

KPMG LLP

New Orleans, Louisiana
February 3, 2003

35

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(IN THOUSANDS, EXCEPT SHARE DATA)

See accompanying notes to consolidated financial statements.

36

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS, EXCEPT PER SHARE DATA)

See accompanying notes to consolidated financial statements.

37

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.

38

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.

39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) ORGANIZATION

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

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) BASIS OF PRESENTATION

The consolidated financial statements include the accounts of Energy
Partners, Ltd., and its wholly-owned subsidiaries (collectively, the Company).
All significant intercompany accounts and transactions are eliminated in
consolidation.

(B) PROPERTY AND EQUIPMENT

The Company uses the successful efforts method of accounting for oil and
natural gas producing activities. Costs to acquire mineral interests in oil and
natural 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.

Leasehold acquisition costs are capitalized. If proved reserves are found
on an undeveloped property, leasehold cost is transferred to proved properties.
Costs of undeveloped leases are expensed over the life of the leases.
Capitalized costs of producing oil and natural gas properties are depreciated
and depleted by the units-of-production method.

The Company calculates the impairment of capitalized costs of proved oil
and natural 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 natural
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, 2002, such costs are
expected to be approximately $67.2 million. To date, $22.7 million has been
accrued and is included in other liabilities in the accompanying consolidated
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.

(C) 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.

(D) DEFERRED FINANCING COSTS

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

40

NOTES TO CONSOLIDATED 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, warrants and stock option awards
and the potential shares that would have a dilutive effect on earnings per
share.

(F) REVENUE RECOGNITION

The Company uses the entitlement method for recording natural gas sales
revenue. 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. At December 31, 2002 and 2001 the
Company had natural gas imbalance receivables of $1.3 million and $0.2 million,
respectively and liabilities of $0.5 million and none, respectively.

(G) STATEMENTS OF CASH FLOWS

For purposes of the statements of cash flows, highly-liquid investments
with original maturities of three months or less are considered cash
equivalents. At December 31, 2002 and 2001, interest-bearing cash equivalents
were approximately $4.4 million and $2.1 million, respectively. Exploration
expenditures incurred are excluded from operating cash flows and included in
investing activities.

(H) HEDGING ACTIVITIES

The Company uses derivative commodity instruments to manage commodity price
risks associated with future crude oil and natural gas production, but does not
use them for speculative purposes. The Company's commodity price hedging program
has utilized financially-settled zero-cost collar contracts to establish floor
and ceiling prices on anticipated future crude oil and natural gas production
and oil and natural gas swaps to fix the price of anticipated future crude oil
and natural gas production. On January 1, 2001, the Company adopted Statement of
Financial Accounting Standards No. 133 (Statement 133), as amended, Accounting
for Derivative Instruments and Hedging Activities. Statement 133 establishes
accounting and reporting standards requiring that derivative instruments,
including certain derivative instruments embedded in other contracts, be
recorded at fair market value and included as either assets or liabilities in
the balance sheet. The accounting for changes in fair value depends on the
intended use of the derivative and the resulting designation, which is
established at the inception of the derivative. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the statement of operations. For derivative
instruments designated as cash-flow hedges, changes in fair value, to the extent
the hedge is effective, will be recognized in other comprehensive income (a
component of stockholders' equity) until settled, when the resulting gains and
losses will be recorded in earnings. Hedge ineffectiveness is measured at least
quarterly based on the relative changes in fair value between the derivative
contract and the hedged item over time. Any change in fair value resulting from
ineffectiveness, as defined by Statement 133, will be charged currently to
earnings.

(I) STOCK-BASED COMPENSATION

The Company has two stock award plans, the Amended and Restated 2000 Long
Term Stock Incentive Plan and the 2000 Stock Option Plan for Non-Employee
Directors (the Plans). The Company accounts for its stock-based compensation in
accordance with Accounting Principles Board's Opinion No. 25, "Accounting For
Stock Issued To Employees" (Opinion No. 25). However, Statement of Financial
Accounting Standards No. 123 (Statement 123), "Accounting For Stock-Based
Compensation" and Statement of Financial Accounting Standards No. 148,
"Accounting for Stock-Based Compensation -- Transition and Disclosure,"
(Statement 148) permits the continued use of the intrinsic value-based method
prescribed by Opinion No. 25, but requires

41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

additional disclosures, including pro-forma calculations of earnings and net
earnings per share as if the fair value method of accounting prescribed by
Statement 123 had been applied. If compensation expense for the Plans had been
determined using the fair-value method in Statement 123, the Company's net
income (loss) and earnings (loss) per share would have been as shown in the pro
forma amounts below (in thousands, except per share amounts):

(J) USE OF ESTIMATES

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America 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.

(K) RECLASSIFICATIONS

Certain reclassifications have been made to the prior period financial
statements in order to conform to the classification adopted for reporting in
fiscal 2002.

(3) INITIAL PUBLIC OFFERING

On November 1, 2000, the Company priced its initial public offering of 5.75
million shares of common stock and commenced trading the following day. After
payment of underwriting discounts and commissions, the Company received net
proceeds of $80.2 million on November 7, 2000. With the proceeds, the Company
retired outstanding debt of $73.9 million and paid approximately $5.1 million to
redeem outstanding Series C Preferred Stock. In connection with the initial
public offering, the Company converted all outstanding Preferred Stock shares
into 9,388,367 shares of common stock.

In November 1999, as a requirement to complete the Preferred Stock
transaction discussed in note 9, management and director stockholders placed in
escrow 3,304,830 shares of common stock. These common shares were originally
issued for cash in early 1998, as part of the initial capitalization of the
Company, prior to the commencement of any significant operations by the Company.
All or a portion of these shares were to be released from escrow only upon the
attainment of specified reserve replacement targets or upon completion of a

42

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

qualifying public offering. On November 7, 2000, 2,545,500 shares were released
as a result of the initial public offering and the remaining shares were
cancelled. Non-cash compensation expense in the fourth quarter of 2000 for the
shares released was approximately $38.2 million. In addition, at the time of the
initial public offering, the Company awarded 139,500 bonus shares to employees
and recognized non-cash compensation expense of approximately $2.1 million
related to these shares. Compensation expense was calculated using $15.00 per
share, the offering price for the Company's common stock.

(4) 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. On November 17, 1999, as required by the Preferred Stock transaction
discussed in note 9, management and director stockholders placed in escrow
3,304,830 shares of common stock. These shares could not be voted by the
management and director stockholders and all or a portion would only be released
from escrow upon the attainment of specified reserve replacement targets or upon
the completion of a qualified initial public offering. Also, as a requirement of
this transaction, Energy Income Fund, L.P. (EIF) returned 3,291,720 shares of
common stock, which were cancelled. All of these shares have been excluded from
the calculation of weighted average common shares from November 17, 1999. On
November 7, 2000, as a result of the initial public offering, 2,545,500 of the
escrow shares were returned to management and director stockholders and have
been included in the calculation of weighted average common shares from that
date. The effect of the preferred stock dividends and accretion of discount on
arriving at income available to common stockholders was $3.3 million for the
year ended December 31, 2002 and the effect of preferred stock dividends and
accretion of issuance costs on arriving at income available to common
stockholders for the years ended December 31, 2001 and 2000 was none and $6.7
million, respectively.

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 stock options and convertible preferred stock shares and the potential shares
that would have a dilutive effect on earnings per share. The number of dilutive
convertible preferred stock shares, warrants and stock options used in computing
diluted earnings per share was 54,976 in 2001 and none in 2002 and 2000, as
these securities were antidilutive in those years.

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) SUPPLEMENTAL CASH FLOW INFORMATION

The following is supplemental cash flow information:

43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is supplemental disclosure of non-cash financing activities:

(6) ACQUISITIONS AND DISPOSITION

On March 31, 2000, the Company purchased an 80% working interest in South
Timbalier 26 for approximately $44.9 million. Additionally, on March 31, 2000,
the Company purchased an average 96.1% working interest in East Bay Field for
approximately $72.3 million. The entire purchase price for both acquisitions was
financed by our bank facility and 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 50% of its working
interest in South Timbalier 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. The results
of operations for each transaction have been included from the respective
acquisition or sale date.

On January 15, 2002, the Company closed the acquisition of Hall-Houston Oil
Company (HHOC). The results of the operations have been included in the
Company's consolidated financial statements since that date. HHOC was an oil and
natural gas exploration and production company with operations focused in the
shallow waters of the Gulf of Mexico. As a result of the acquisition, the
Company has a strengthened management team, expanded exploration opportunities
as well as a reserve portfolio and production that are more balanced between oil
and natural gas.

The HHOC acquisition was completed for consideration consisting of $38.4
million liquidation preference of newly authorized and issued Series D
Exchangeable Convertible Preferred Stock (Series D Preferred Stock) with a fair
value of $34.7 million discounted to effect the increasing dividend rate, $38.4
million of 11% Senior Subordinated Notes, due 2009 (the Notes), 574,931 shares
of common stock with a fair value of $3.3 million determined based on the
average market price of the Company's common stock over the period of two days
before and after the terms of the acquisition were agreed to and announced, $9.0
million of cash including 3.9 million of accrued interest and prepayment fees
paid to former debt holders, and warrants to purchase four million shares of
common stock. Of the warrants, one million have a strike price of $9.00 and
three million have a strike price of $11.00 per share. The warrants had a fair
value of approximately $3.0 million based on a third party valuation and are
exercisable beginning January 15, 2003 and expiring on January 15, 2007. In
addition, the Company incurred approximately $3.6 million in expenses in
connection with the acquisition and assumed HHOC's working capital deficit.

Former preferred stockholders of HHOC also have the right to receive
contingent consideration based upon a percentage of the amount by which the
before tax net present value of proved reserves related, in general, to
exploratory prospect acreage held by HHOC as of the closing date exceeds a net
present value discounted at 30%. The contingent consideration may be paid in the
Company's common stock or cash at the Company's option (with a minimum of 20% in
cash for each payment) and in no event will exceed a value of $50 million. Due
to the uncertainty inherent in estimating the value of contingent consideration,
total final consideration will not be determined until March 1, 2007. The
contingent consideration, if any, will be capitalized as additional purchase

44

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

price. The following table summarizes the fair value of the assets acquired and
liabilities assumed at the date of acquisition:

The unaudited pro-forma results of operations, assuming that the HHOC
acquisition occurred on January 1, 2001, is as follows (in thousands, except per
share amounts):

The pro-forma financial information does not purport to be indicative of
the results of operations that would have occurred had the acquisition taken
place at the beginning of the periods presented or future results of operations.

Following the completion of the acquisition, management of the Company
assessed the technical and administrative needs of the combined organization. As
a result, 14 redundant positions were eliminated including finance,
administrative, geophysical and engineering positions in New Orleans and
Houston. Total severance costs under the plan were $1.2 million.

(7) PROPERTY AND EQUIPMENT

The following is a summary of property and equipment at December 31, 2002
and 2001:

Substantially all of the Company's oil and natural gas properties serve as
collateral for its bank facility.

45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(8) LONG-TERM DEBT

In June 1999, the Company entered into a reducing revolving line of credit
with a group of banks (bank facility). In order to finance the acquisitions of
South Timbalier 26 and East Bay Field, as discussed in note 6, the Company
amended its bank facility to provide for a $90.0 million reducing revolving line
of credit and a $25.0 million reducing bridge financing. As stipulated in the
bank facility, the proceeds from the asset sale of $36.6 million were used to
reduce the outstanding borrowings to approximately $71.8 million. In conjunction
with the initial public offering described in note 3, the outstanding borrowings
were repaid.

The bank facility, as amended on November 1, 2002, provides for a $100
million borrowing base that is subject to redetermination based on the proved
reserves of the oil and gas properties that serve as collateral for the bank
facility as set out in the reserve report delivered to the banks each April 1
and October 1. The bank facility is available through March 30, 2005 with
interest permitted at both prime rate based borrowings and London interbank
borrowing rate (LIBOR) borrowings plus a floating spread. The spread will float
up or down based on our utilization of the bank facility. The spread can range
from 0% to 0.75% above prime and 1.5% to 2.25% above LIBOR. Indebtedness under
the bank facility is secured by substantially all of the assets of the Company.
The weighted average interest rate at December 31, 2002 and 2001 was 3.18% and
3.41%, respectively. The bank facility contains customary events of default and
requires that the Company satisfy various financial covenants with which the
Company was in compliance at December 31, 2002.

In addition, as stated in note 6, the Company issued the Notes due January
15, 2009 with annual interest of 11%, payable semi-annually on each January 15
and July 15, commencing July 15, 2002. If at any time while the Notes are
outstanding, the Company completes a public or Rule 144A offering of debt
securities, to the extent permitted by the bank facility, the proceeds of such
offering will be used to prepay the principal amount of the Notes plus accrued
interest.

Total long-term debt outstanding at December 31, 2002 and 2001 were as
follows:

Maturities of long-term debt as of December 31, 2002 were as follows (in
thousands):

2003........................................................ $ 92
2004........................................................ 99
2005........................................................ 65,108
2006........................................................ 109
2007........................................................ --
Thereafter.................................................. 38,371
--------
$103,779
========

On April 15, 1998, the Company entered into a $20.0 million financing
agreement with EIF. On February 10, 1999, the financing agreement was amended to
increase the facility to $25.0 million. On

46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

November 17, 1999, the Company used $15.0 million of the proceeds from the
Preferred Stock transaction, discussed in note 9, to pay down the debt due to
EIF. The remaining $10.0 million was repaid in November 2000 using proceeds from
the initial public offering.

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 9. The warrant was 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 a
qualifying public offering. The warrant was assigned no value at the date of
issuance. EIF exercised its option to convert the warrant in January 2001,
receiving 466,245 shares of common stock.

(9) PREFERRED STOCK

In 1999, the Company authorized 1,700,000 shares of redeemable preferred
stock (Preferred Stock) having a par value of $1.00 per share, of which
1,550,000 shares were designated as Series A and Series B Redeemable Cumulative
Convertible Preferred Stock and Series C Redeemable Cumulative Preferred Stock.
The remaining 150,000 shares were undesignated. In November 1999, the Company
entered into a stock purchase agreement whereby 600,000 shares of Series A and B
Preferred Stock were sold to Evercore Capital Partners L.P. (Evercore) for $60.0
million excluding issuance costs.

The Preferred Stock earned 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 were payable in
additional fully paid and non-assessable shares (no further investment is
required by the stockholders) of Series C Preferred Stock. The dividends on the
Series B Preferred Stock were payable in additional fully paid and non-
assessable shares of Series B Preferred Stock. The dividends on the Series C
Preferred Stock were payable in cash. All accrued dividends were recorded as an
increase to the carrying value of the Preferred Stock. Through November 7, 2000,
there were $7.1 million of Preferred Stock dividends in arrears, of which
approximately $2.0 million or 155,470 shares were Series B Preferred Stock
recorded at fair value. These shares were converted to common stock at the time
of the public offering and the Series C preferred stock dividends of
approximately $5.1 million were paid in cash.

In connection with the acquisition of HHOC, in January 2002, the series A,
B and C classes were returned to undesignated and the Board of Directors of the
Company designated a new class of preferred stock. The Company authorized
550,000 shares of Series D Preferred Stock, having a par value of $1.00 per
share, of which 383,707 shares were issued in the acquisition of HHOC.

The Series D Preferred Stock earns cumulative dividends payable
semiannually in arrears on June 30 and December 31 of each year as follows:

Any dividends accrued on or prior to December 31, 2005 shall, when
declared, be payable in cash at the dividend rate per-share based on the stated
value of $100. Any dividends accrued after December 31, 2005 and on or before
December 31, 2008 shall, when declared, be payable, at the option of the
Company, either in cash at the dividend rate per-share based on the stated value
of $100 or by issuing dividend shares having an aggregate value equal to the
dividend rate per-share based on the stated value of $100. The Company may, at
its option on or after December 31, 2004, redeem the Series D Preferred Stock in
whole, at a redemption price per-share equal to $100 plus accrued and unpaid
dividends. The Company may also, at its option, on any dividend payment date,
exchange the Series D Preferred Stock, in whole, along with any unpaid
dividends, for an equal principal amount

47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of Exchangeable Notes. At the time of the exchange, holders of outstanding
shares will be entitled to receive $100 principal amount of Exchangeable Notes
for each $100 stated value of Series D Preferred Stock and accrued and unpaid
dividends. The Exchangeable Notes mature January 15, 2009 and the coupon follows
the same schedule as that of the dividends on the Series D Preferred Stock. Each
share of the Series D Preferred Stock is convertible at the option of the record
holder at any time, into the number of shares of common stock determined by
dividing $100 by the conversion price of $8.54 as adjusted pursuant to the terms
of the Series D Preferred Stock designation. In 2002, 1,445.8 shares of Series D
Preferred Stock were converted into 16,929 shares of common stock.

(10) SIGNIFICANT CUSTOMERS

The Company had oil and natural gas sales to three customers accounting for
approximately 41 percent, 27 percent, and 11 percent, respectively, of total oil
and natural gas revenues, excluding the effects of hedging activities, for the
year ended December 31, 2002. The Company had oil and natural gas sales to three
customers accounting for approximately 38 percent, 37 percent and 15 percent,
respectively, of total oil and natural gas revenues, excluding the effects of
hedging activities, for the year ended December 31, 2001. The Company had oil
and natural gas sales to two customers accounting for 53 percent and 18 percent,
respectively, of total oil and natural gas revenues, excluding the effects of
hedging activities, for the year ended December 31, 2000.

(11) HEDGING ACTIVITIES

The Company enters into hedging transactions with major financial
institutions to reduce exposure to fluctuations in the price of oil and natural
gas. Crude oil hedges are settled based on the average of the reported
settlement prices for West Texas Intermediate crude on the NYMEX for each month.
Natural gas hedges are settled based on the average of the last three days of
trading of the NYMEX Henry Hub natural gas contract for each month. The Company
also uses financially-settled crude oil and natural gas swaps, zero-cost collars
and options used to provide floor prices with varying upside price
participation.

On December 12, 2001, the Company purchased a financially-settled put
swaption (put swaption) in anticipation of the acquisition of Hall-Houston Oil
Company and affiliated interests (collectively, HHOC). The put swaption provided
the Company with a financially-settled natural gas swap at $2.95 per Mmbtu for
10,950,000 Mmbtu (30,000 Mmbtu per day) for the period of February 2002 through
January 2003 and the option to cancel this swap on January 15, 2002. The cost to
enter into the contract was $2.4 million. On January 15, 2002, the Company
exercised its right provided by the put swaption to retain the swap at $2.95 per
Mmbtu.

With a financially-settled swap, the counterparty is required to make a
payment to the Company if the settlement price for any settlement period is
below the hedged price for the transaction, and the Company is required to make
a payment to the counterparty if the settlement price for any settlement period
is above the hedged price for the transaction. With a zero-cost collar, the
counterparty is required to make a payment to the Company if the settlement
price for any settlement period is below the floor price of the collar, and the
Company is required to make a payment to the counterparty if the settlement
price for any settlement period is above the cap price for the collar.

48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company had the following hedging contracts as of December 31, 2002:

Subsequent to December 31, 2002 we entered into the following contracts:

For the years ended December 31, 2002, 2001 and 2000, hedging activities
reduced oil and gas revenues by $5.0, $3.5 and $10.6 million, respectively.

The Company's derivative instruments qualify as cash-flow hedges. In
accordance with the transition provisions of Statement 133, on January 1, 2001,
the Company recorded a net-of-tax cumulative-effect-type loss adjustment of $2.4
million in accumulated other comprehensive income to recognize at fair value all
derivatives that were designated as cash-flow hedging instruments. During 2001,
as the contracts settled, losses of $2.4 million were transferred from
accumulated other comprehensive income and the fair value of outstanding
derivative assets increased $1.0 million resulting in an ending balance of $1.0
million in accumulated other comprehensive income at December 31, 2001 related
to hedging activities. During 2002, losses of $3.2 million, net of tax, were
transferred from accumulated other comprehensive income (loss), and the fair
value of outstanding derivative instruments decreased by $10.0 million ($6.4
million net of tax) to a liability of $3.4 million ($2.2 million net of tax)
resulting in an ending balance of $2.2 million related to hedging activities in
accumulated other comprehensive income (loss) at December 31, 2002. Based upon
current prices, the Company expects to transfer approximately $3.2 million of
net deferred losses in accumulated other comprehensive income (loss) as of
December 31, 2002 to earnings during 2003 when the forecasted transactions
actually occur.

(12) FAIR VALUE

The following table presents the carrying amounts and estimated fair values
of financial instruments held by the Company at December 31, 2002 and 2001. The
fair value of a financial instrument is the amount at which the instrument could
be exchanged in a current transaction between willing parties. The table
excludes cash and cash

49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

equivalents, trade accounts receivable, noncurrent assets, trade accounts
payable and accrued expenses and derivative instruments, all of which had fair
values approximating carrying amounts. The fair value of current and long-term
debt is estimated based on current rates offered the Company for debt of the
same maturities. The Company has off-balance sheet exposures relating to certain
financial guarantees and letters of credit. The fair value of these, which
represents fees associated with obtaining the instruments, was nominal.

(13) INCOME TAXES

Components of income tax expense (benefit) for the years ended December 31,
2002, 2001 and 2000 are as follows:

The reasons for the differences between the effective tax rates and the
"expected" corporate federal income tax rate of 35% is as follows:

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The tax effects of temporary differences that give rise to significant
portions of the current tax asset and net deferred tax liability at December 31,
2002 and 2001 are presented below:

At December 31, 2002, the Company had net operating loss carryforwards of
approximately $48.2 million, which are available to reduce future federal
taxable income. The net operating loss carryforwards begin expiring in the years
2018 through 2022. 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, reversal of taxable temporary differences and tax
planning strategies. As a result, no valuation allowance has been provided.

(14) EMPLOYEE BENEFIT PLANS

The Company has outstanding stock options and restricted stock awards under
the Amended and Restated 2000 Long Term Stock Incentive Plan. The amended plan
was approved by stockholders on May 9, 2002. The plan provides for awards of
options to purchase shares of the Company's common stock and performance shares.
The plan is administered by the Compensation Committee of the board of directors
or such other committee as may be designated by the board of directors. The
Compensation Committee is authorized to select the employees of the Company and
its 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 4,800,000
and includes the grant of options and restricted stock discussed below.

In April 2000, an employee, pursuant to her 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 vested 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 in April 2001,
150,000 shares at $8.82 per share in April 2002 and the remaining shares at
$10.14 in April 2003. The grant date fair value of the restricted stock and
options was $17.00.

The Company issued 32,750 and 60,240 shares of common stock as restricted
stock awards to certain employees and officers in two separate grants during
2002. The restricted shares in the first grant had a grant date fair value of
$7.98 per share and vest January 17, 2004. The restricted shares in the second
grant had a grant date fair value of $8.30 and vest January 17, 2005.

The Company has recognized non-cash compensation expense of $0.5 million,
$1.7 million and $2.8 million in 2002, 2001 and 2000, respectively, related to
the restricted stock and stock option grants. At December 31, 2002, there was
$0.6 million of deferred stock based compensation expense related to these
awards, which will be recognized over the remaining vesting period.

51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The board of directors also adopted the 2000 Stock-Option Plan for
Non-Employee Directors on September 12, 2000, and the stockholders 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 was made to each non-employee director upon
consummation of the public 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 value was 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.

A summary of stock options granted under the incentive plans for the years
ended December 31, 2002 and 2001 are as follows:

A summary of information regarding stock options outstanding at December
31, 2002 is as follows:

The Company also has a 401(k) Plan (the Plan) that covers all employees.
The Plan was amended in 2002 such that, commencing July 1, 2002 the Company
matches 50% of each individual participant's contribution not to exceed 2% of
the participant's compensation. The contributions may be in the form of cash or
the Company's common stock. The Company made matching contributions to the Plan
of 9,206 shares of common stock valued at approximately $84,000 in 2002.

(15) COMMITMENTS AND CONTINGENCIES

The Company has operating leases for office space and equipment, which
expire on various dates through 2011.

52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Future minimum lease commitments as of December 31, 2001 under these
operating leases are as follows (in thousands):

2003........................................................ $ 2,339
2004........................................................ 2,453
2005........................................................ 2,393
2006........................................................ 2,871
2007........................................................ 1,959
Thereafter.................................................. 5,450
-------
$17,465
=======

Rent expense for the years ended December 31, 2002, 2001 and 2000 was $3.3
million, $1.8 million and $0.9 million, respectively.

Commencing January 1, 2002, the Company is required to make monthly
deposits of $250,000 into a trust for future abandonment costs at East Bay. The
Company is not entitled to access the trust fund in order to draw funds for
abandonment purposes prior to December 31, 2003. Monthly deposits are not
required to be made for fiscal year 2004 and are to resume January 1, 2005,
however, beginning December 31, 2003 the minimum balance in the trust must be
maintained at $6.0 million until such time that the remaining abandonment
obligation is less than that amount. Therefore if funds are drawn to pay for
ongoing abandonment activities, deposits may be necessary. These deposits are
classified as other assets in the accompanying consolidated balance sheets.

The Company has agreed to purchase $1.7 million, $1.5 million and $0.9
million of seismic-related services during the years ended December 31, 2003,
2004 and 2005, respectively. In addition to the above commitments, during 2002
the Company entered into a contract to purchase $5.1 million of additional
seismic-related services, which can be purchased at anytime on or before
February 28, 2005. During 2002 the Company paid $0.5 million for seismic-related
services pertaining to this contract and has a future commitment of $4.6 million
under this contract.

In February 2003, the Company settled a lawsuit filed in 2001 for $2
million. The Company expects a portion of the settlement to be reimbursed by its
insurance carriers, however; at this time the amount of any reimbursement cannot
be estimated and is not reflected in the consolidated balance sheets or
statements of operations.

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.

(16) 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 oilfield
equipment and services to the Company. The Company incurred gross costs, both
capital and lease operating on behalf of itself and its working interest
partners, from this service provider of approximately $4.0 million, $4.2 million
and $3.9 million in 2002, 2001 and 2000, respectively. Loss of this service
provider would not have a material adverse effect on the operations of the
Company.

Pursuant to the Company's stockholder agreement with Evercore, the Company
paid an affiliate of Evercore a monitoring fee of $250,000 for each of the years
2002, 2001 and 2000. This fee will be paid annually until Evercore beneficially
owns less than 10% of the Company. An affiliate of Evercore provided
investment-banking advisory services to the Company in relation to the January
2002 acquisition of HHOC. The Company paid $0.4 million for these services in
2002.

53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Certain officers and their affiliates that held interests prior to the HHOC
transaction continue to be royalty and working interest owners in individual
properties acquired from HHOC and operated by the Company. The officers and
their affiliates are billed for and pay their proportionate share of drilling
and operating costs in the normal course of business.

(17) INTERIM FINANCIAL INFORMATION (UNAUDITED)

The following is a summary of consolidated unaudited interim financial
information for the years ended December 31, 2002 and 2001 (in thousands, except
per share data):

(18) NEW ACCOUNTING POLICIES

In 2001, the Financial Accounting Standards Board (FASB) issued Statement
143, Accounting for Asset Retirement Obligations (Statement 143). Statement 143
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred, a corresponding
increase in the carrying amount of the related long-lived asset and is effective
for fiscal years beginning after June 15, 2002. The Company will adopt Statement
143 effective January 1, 2003, using the cumulative effect approach to recognize
transition amounts for asset retirement obligations, asset retirement costs and
accumulated depreciation. The Company currently records estimated costs of
dismantlement, removal, site restoration and similar activities as part of its
depreciation, depletion and amortization for oil and gas properties and records
a separate liability for such amounts in other liabilities. The effect of
Statement 143 on the Company's results of operations and financial condition at
adoption is expected to include a net increase in long-term liabilities of $14.2
million; an increase in net property, plant and equipment of $17.8 million; a
cumulative effect of adoption income of $2.3 million net of deferred income
taxes and a deferred tax liability of $1.3 million. Subsequent to adoption, the
Company does not expect this standard to have a material impact on the Company's
financial position or its results of operations.

54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During the second quarter of 2002, the FASB issued Statement 145,
Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13 and Technical Corrections (Statement 145). This statement rescinds SFAS No.
4, Reporting Gains and Losses from Extinguishments of Debt, and requires that
all gains and losses from extinguishments of debt should be classified as
extraordinary items only if they meet the criteria of APB No. 30. Applying APB
No. 30 will distinguish transactions that are part of an entity's recurring
operations from those that are unusual or infrequent or that meet the criteria
for classification as an extraordinary item. Any gain or loss on extinguishment
of debt that was classified as an extraordinary item in prior periods presented
that does not meet the criteria in APB No. 30 for classification as an
extraordinary item must be reclassified. The Company will adopt the provisions
related to the rescission of SFAS No. 4 as of January 1, 2003. The adoption of
Statement 145 is not expected to have an impact on the results of operations or
financial position of the Company.

In June 2002, the FASB issued Statement 146, Accounting for Costs
Associated with Exit or Disposal Activities (Statement 146). Statement 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and requires that liabilities associated with these costs be
recorded at their fair value in the period in which the liability is incurred.
Statement 146 will be effective for disposal activities initiated after December
31, 2002. The Company will adopt the provisions related to Statement 146 as of
January 1, 2003; however, the adoption is not expected to have an impact on the
results of operations or financial position.

In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires a company to
recognize a liability for the obligations it has undertaken in issuing a
guarantee. This liability would be recorded at the inception of a guarantee and
would be measured at fair value. The measurement provisions of this statement
apply prospectively to guarantees issued or modified after December 31, 2002.
The disclosure provisions apply to financial statements for periods ending after
December 15, 2002. The Company does not currently have guarantees that require
disclosure. The Company will adopt the measurement provisions of this statement
in the first quarter of 2003 and the adoptions is not expected to have a
material effect on its financial position or results of operations.

In December 2002, the FASB issued Statement 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure (Statement 148). Statement 148
provides alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, Statement 148 amends the disclosure requirements of Statement 123,
"Accounting for Stock-Based Compensation," to require more prominent and
frequent disclosures in financial statements about the effects of stock-based
compensation. The transition guidance and annual disclosure provisions of
Statement 148 are effective for fiscal years ending after December 15, 2002,
while the interim disclosure provisions are effective for periods beginning
after December 15, 2002. The Company is currently assessing the impact of the
transition options presented in Statement 148 and adoption of the disclosure
provisions required by Statement 148 are included in note 2.

In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46). FIN 46 requires a company to
consolidated a variable interest entity if it is designated as the primary
beneficiary of that entity even if the company does not have a majority of
voting interest. A variable interest entity is generally defined as a entity
where its equity is unable to finance its activities or where the owners of the
entity lack the risk and rewards of ownership. The provisions of FIN 46 apply
immediately to variable interest entities created after January 31, 2003 and to
variable interest entities in which an enterprise obtains an interest after that
date. The adoption of FIN 46 is not currently expected to have an effect on the
Company's financial position or results of operations when adopted.

(19) SUPPLEMENTARY OIL AND NATURAL 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

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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.

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

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

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Costs incurred for oil and natural gas property acquisition, exploration
and development activities for the years ended December 31, 2002, 2001 and 2000
are as follows:

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 (Statement 69),
"Disclosures about Oil and Gas Producing Activities". 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 Statement 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.

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and natural gas reserves for the years
ended December 31, 2002, 2001 and 2000 is as follows:

The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 2002 was based on
period-end prices of $4.83 per Mcf for natural gas and $29.53 per barrel for
crude oil. The December 31, 2001 computation was based on period-end prices of
$2.71 per Mcf for natural gas and $18.21 per barrel for crude oil. Spot prices
as of February 26, 2003 were $8.79 per Mmbtu for natural gas and $34.50 per
barrel for crude oil before adjustment for lease quality, transportation fees
and price differentials.

58

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

For information required by Item 10 regarding our directors and executive
officers, see the definitive Proxy Statement of Energy Partners, Ltd. for the
Annual Meeting of Stockholders to be held on May 6, 2003, which will be filed
with the Securities and Exchange Commission and is incorporated herein by
reference, and "Part I -- Item 4A. Executive Officers".

ITEM 11. EXECUTIVE COMPENSATION

For information required by Item 11 see the definitive Proxy Statement of
Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May
6, 2003, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Except as set forth below, for the information required by Item 12 see the
definitive Proxy Statement of Energy Partners, Ltd. for the Annual Meeting of
Stockholders to be held on May 6, 2003, which will be filed with the Securities
and Exchange Commission and is incorporated herein by reference.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table provides information as of December 31, 2002, with
respect to compensation plans under which our equity securities are authorized
for issuance.

See note 14 to our consolidated financial statements for further
information regarding the significant features of the above plans.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For information required by Item 13 see the definitive Proxy Statement of
Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May
6, 2003, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

ITEM 14. CONTROLS AND PROCEDURES

Within 90 days prior to the date of this report, our Chief Executive
Officer and Chief Financial Officer completed an evaluation of our disclosure
controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) of the
Securities and Exchange Act of 1934, as amended). Based on this evaluation, our
Chief Executive Officer and Chief Financial Officer believe that as of the date
of the evaluation our disclosure controls and procedures are effective.

59

There were no significant changes (including corrective action with regard
to significant deficiencies or material weaknesses) in the Company's internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of the most recently completed evaluation.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

1. FINANCIAL STATEMENTS:

The following financial statements are included in Part II of this Report:

Independent Auditor's Report

Consolidated Balance Sheets as of December 31, 2002 and 2001

Consolidated Statements of Operations for the years ended December 31,
2002, 2001 and 2000

Consolidated Statements of Changes in Stockholders' Equity for the years
ended December 31, 2002, 2001 and 2000

Consolidated Statements of Cash Flows for the years ended December 31,
2002, 2001 and 2000

Notes to the Consolidated Financial Statements

2. REPORTS ON FORM 8-K

None

3. EXHIBITS

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

* Filed herewith

62

SIGNATURES

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

ENERGY PARTNERS, LTD.

By: /s/ RICHARD A. BACHMANN
------------------------------------
Richard A. Bachmann
Chairman, President
and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed by the following persons on behalf of the registrant in
the capacities and on the date indicated.

63

Certifications of the Executive Vice President and Chief Financial Officer
and Chairman, President, and Chief Executive Officer of Energy Partners, Ltd.
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Suzanne V. Baer, certify that:

1. I have reviewed this annual report on Form 10-K of Energy Partners,
Ltd.

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this annual report;

3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for the periods presented in this annual
report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;

b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing
the equivalent functions):

a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b. any fraud, whether material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officer and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

/s/ SUZANNE V. BAER
--------------------------------------
Suzanne V. Baer
Executive Vice President and Chief
Financial Officer

Dated: March 13, 2003

65

I, Richard A. Bachmann, certify that:

1. I have reviewed this annual report on Form 10-K of Energy Partners,
Ltd.

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this annual report;

3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for the periods presented in this annual
report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;

b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing
the equivalent functions):

a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officer and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

/s/ RICHARD A. BACHMANN
--------------------------------------
Richard A. Bachmann
Chairman, President and Chief
Executive Officer

Dated: March 13, 2003

66

Certification Accompanying Form 10-K Report of Energy Partners, Ltd.
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chapter 63, Title 18
U.S.C. Section 1350(a) and (b))

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the
undersigned hereby certifies in his capacity as an officer of Energy Partners,
Ltd. (the "Company") that the Annual Report of the Company on Form 10-K for the
period ended December 31, 2002 fully complies with the requirements of Section
13(a) of the Securities Exchange Act of 1934 and that the information contained
in such Report fairly presents, in all material respects, the financial
condition and the results of operations of the Company at the end of and for the
periods covered by such Report.

/s/ RICHARD A. BACHMANN
--------------------------------------
Richard A. Bachmann
Chairman, President
and Chief Executive Officer

Dated: March 13, 2003

/s/ SUZANNE V. BAER
--------------------------------------
Suzanne V. Baer
Executive Vice President
and Chief Financial Officer

Dated: March 13, 2003

67

EXHIBIT INDEX

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* Filed herewith