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, 2003

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 Act). Yes [X] No [ ]

The aggregate market value of the common stock held by non-affiliates of
the registrant at June 30, 2003 based on the closing price of such stock as
quoted on the New York Stock Exchange on that date was $213,337,290.

As of February 25, 2004 there were 32,455,736 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 2004 Annual Meeting of Stockholders have been
incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

1

FORWARD LOOKING STATEMENTS

All statements other than statements of historical fact contained in this
Report on Form 10-K ("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, 2003, we had estimated proved reserves
of approximately 134.4 Bcf of natural gas and 27.4 Mmbbls of oil, or an
aggregate of approximately 49.8 Mmboe, with a present value of estimated pre-tax
future net cash flows of $967.4 million, and a standardized measure of
discounted future net cash flows of $529.4 million.

Since our incorporation in January 1998 by Richard A. Bachmann, our
founder, chairman, president and chief executive officer, we have assembled a
team of geoscientists and management professionals with considerable
region-specific geological, geophysical, technical and operational experience.
We have grown 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 natural gas fields in the Gulf of Mexico Shelf
area, including the acquisition of Hall-Houston Oil Company ("HHOC") in early
2002. 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. This acquisition
also expanded our technical knowledge base through the addition of high 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.

On November 1, 2000, we consummated our initial public offering and began
trading our common shares 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. In addition, by
the time of our 2004 Annual Meeting of Stockholders, we will post our Corporate
Governance Guidelines and the charters for our Audit, Compensation and
Nominating Committees on our web site. Copies of such information are also
available by writing to The Secretary of the Company at 201 St. Charles Avenue,
Suite 3400, New Orleans, Louisiana 70170. 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.

2

EXPLORATION AND DEVELOPMENT EXPENDITURES

Our exploration and development expenditures for 2003 totaled $112.7
million inclusive of an $0.9 million contingent consideration payment to former
HHOC stockholders resulting from the January 2002 acquisition of HHOC. For 2004,
we have budgeted exploration and development expenditures of $125 million. This
budget includes a mixture of lower risk development and exploitation wells,
moderate risk exploration opportunities and higher risk, higher potential
exploration projects and does not include acquisitions.

OUR PROPERTIES

At December 31, 2003, we had interests in 24 producing fields and 6 fields
under development, all of which are located in the Gulf of Mexico Shelf region.
These fields fall into three focus areas which we identify as our Eastern,
Central and Western areas. The Eastern area is comprised of two fields,
including the East Bay field. The Central area is comprised of six fields, four
of which are contiguous and together cover most of the Bay Marchand salt dome.
The Western area is comprised of 17 producing fields.

EASTERN AREA

East Bay is the key asset in our Eastern area and is located 89 miles
southeast of New Orleans near the mouth of the Mississippi River. East Bay
contains producing wells located onshore along the coastline and in water depths
ranging up to approximately 85 feet. East Bay encompasses nearly 48 square miles
and is comprised primary of, South Pass 24, 26 and 27 fields. Through recent
state and federal lease sales, we acquired acreage that is contiguous to East
Bay in several additional South Pass and West Delta blocks. We are the operator
of these fields and own an average 93% working interest with our working
interest ranging from 50% to 100% and our net revenue interest ranging from 42%
to 86%. Inclusive of all lease acquisitions, our lease area covers 42,103 gross
acres (39,154 net acres).

Our Eastern area operations accounted for approximately 45% of our net
daily production and 22% ($25.3 million) of our capital expenditures during
2003.

CENTRAL AREA

The focus of our Central area operations is Greater Bay Marchand, which is
located approximately 60 miles south of New Orleans in water depths of 60 feet
or less and encompasses nearly 100 square miles. Our key assets in Greater Bay
Marchand include the Bay Marchand, South Timbalier 26 and South Timbalier 41
fields.

Through a series of acquisitions we obtained a 50% interest in the South
Timbalier 26 field in early 2000. We continue to serve as operator of this field
where we have interests in 13 producing wells. In 2003, the Company drilled a
well in the South Timbalier 41 field, our Rock Creek discovery, that is
currently under development. The field may be able to utilize existing
infrastructure owned by us in the adjacent South Timbalier 26 field and is
expected to be on production by mid 2004.

Our Central area operations accounted for approximately 16% of our net
daily production and 21% ($23.7 million) of capital expenditures during 2003.

WESTERN AREA

In connection with the HHOC acquisition in early 2002, we added ten
producing fields and one field under development to our property portfolio in
our Western area. The properties acquired in the acquisition are located in
water depths ranging from 20 to 476 feet. We operate all of these properties,
with working interests ranging from 17% to 100%. Subsequent to the acquisition,
we acquired 5 leases at the March 2002 and 2003 federal lease sales and also
acquired working interests in several additional leases through trades with
industry partners, which brought our total number of fields in this area at
December 31, 2003 to 17 producing fields with another five under development.

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Our Western area operations accounted for approximately 39% of our net
daily production and 57% ($63.7 million) of our capital expenditures during
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, 2003, 2002 and
2001. The December 31, 2003 and 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
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, 2003 amount was calculated using a period-end oil price of
$30.88 per barrel and a period-end natural gas price of $6.15 per Mcf, while
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 and
the December 31, 2001 amount was calculated using a period-end oil price of
$18.21 per barrel and a period-end 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, 2003 were
9,600 Mbbls and 41,294 Mmcf.

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."

4

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, 2003:

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. Sixteen
gross oil wells and five gross natural gas wells have dual completions.

5

ACREAGE

The following table sets forth information as of December 31, 2003 relating
to acreage held by us. Developed acreage is assigned to producing wells.

Leases covering 5% of our undeveloped net acreage will expire in 2004,
approximately 10% in 2005, 42% in 2006, 11% in 2007, and 32% in 2008.

WELL ACTIVITY

The following table shows our well activity for the years ended December
31, 2003, 2002 and 2001. 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
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undeveloped properties. We investigate title prior to the consummation of an
acquisition of producing properties and before the commencement of drilling
operations on undeveloped properties. We have obtained or conducted a thorough
title review on substantially all of our producing properties and believe that
we have satisfactory title to such properties in accordance with standards
generally accepted in the oil and natural gas industry.

REGULATORY MATTERS

REGULATION OF TRANSPORTATION AND SALE OF NATURAL GAS

Historically, the transportation and sale for resale of natural gas in
interstate 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") and its predecessors. 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 ("OCS") 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 OCS with greater assurance of open access
service on pipelines located on the OCS and non-discriminatory rates and
conditions of service on such pipelines.

It should be noted that FERC currently is considering whether to
reformulate its test for defining non-jurisdictional gathering in the shallow
waters of the OCS and, if so, what form that new test should take. The stated
purpose of this initiative is to devise an objective test that furthers the
goals of the NGA by protecting producers from the unregulated market power of
third-party transporters of gas, while providing incentives for investment in
production, gathering and transportation infrastructure offshore. While we
cannot predict whether FERC's gathering test ultimately will be revised and, if
so, what form such revised test will take, any test that refunctionalizes as
FERC-jurisdictional transmission facilities currently classified as gathering
would

7

impose an increased regulatory burden on the owner of those facilities by
subjecting the facilities to NGA certificate and abandonment requirements and
rate regulation.

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 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 materially
different from the effect of such regulation on 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 materially different from the
effect of such regulation on 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 OCS 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 plugging and abandonment and reports concerning
operations. The 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
8

abandonment of wells. Many states also restrict production to the market demand
for oil and natural gas, and 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.

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.

9

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 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

10

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 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
11

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.
This order 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 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 or the State of Texas, as applicable.
12

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 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.

13

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;

- the price and availability of liquefied natural gas imports;

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

- 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 assist in the preparation of 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 these 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
14

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 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.

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

During the month of December 2003, 36% 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, 2003, approximately 48% 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 SUBJECTS 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 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.

15

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.

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 additional 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 additional external funding on terms acceptable to us.

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
16

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

In addition, Delaware law imposes some restrictions on mergers and other
business combinations between us and any holder of 15% or more of our
outstanding common stock.

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 an 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"). The contract has a 60 day cancellation
policy and can be cancelled by either party. In the event that the contract is
cancelled by us, Shell has the right to match any other offers we receive for
purchase of our oil production. 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 Louis Dreyfus Energy
Services, L.P. ("Dreyfus"). 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 2003, Shell accounted for approximately 30
percent and Dreyfus 10 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, 2003, we had 142 full-time employees, including 46
geoscientists, engineers and technicians and 54 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.

17

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.

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 natural 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 natural 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 34 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.

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.

18

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.

T. Rodney Dykes joined us in April 2001 as general manager of operations
and was elected vice president of operations in July 2001. He served as our vice
president of exploitation for the period from March 2002 through July 2003 and
was elected senior vice president -- production in July 2003. Mr. Dykes has over
25 years experience in the energy industry. Immediately prior to joining us, Mr.
Dykes worked as an independent consultant. From 1994 to 1999, Mr. Dykes held
various positions with CMS Oil and Gas Company, including divisional operations
manager, vice president of operations and vice president of business
development. From 1980 to 1994, he held various technical, drilling and
production management positions with Maxus Energy. Prior to 1980, Mr. Dykes was
a petroleum engineer with Kerr McGee.

William Flores, Jr. joined us in August 2003 as senior vice
president -- drilling. Mr. Flores has over 22 years experience in the energy
industry. From 1999 to 2003, he was senior vice president of drilling for Ocean
Energy, Inc. and from 1993 to 1999 he was vice president of operations of Ocean
Energy, Inc. From 1988 to 1993, Mr. Flores was a senior drilling engineer for
CNG Producing. From 1983 to 1988, he worked as a consulting engineer at the
consulting firm of Stokes and Spiehler. Prior to 1983, Mr. Flores was a
petroleum engineer for Apache Oil 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 25, 2004, the last reported sale price of our common stock on
the New York Stock Exchange was $13.29 per share.

As of February 25, 2004, there were approximately 129 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.

19

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. These charges were partially offset by a gain on sale
of oil and natural gas assets of $7.8 million.

(2) The 2003 net income includes a cumulative effect of change in accounting
principle resulting from the adoption of Statement 143, which increased net
income $2.3 million, net of deferred income taxes of $1.3 million.

(3) Net income (loss) available to common stockholders is computed by
subtracting preferred stock dividends and accretion of discount of $3.5
million and $3.3 million from net income (loss) for the years ended December
31, 2003 and 2002, respectively; 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.

20

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

OVERVIEW

We were incorporated in January 1998 and operate in a single segment as an
independent oil and natural gas exploration and production company. Our
operations are concentrated in the shallow to moderate depth waters of the Gulf
of Mexico Shelf.

In 2003, we reported another year of growth and progress with the best year
on a per-share basis over our six-year history. Our strong cash flow provided us
the flexibility to make necessary and appropriate investments to continue our
long-term growth strategy. Our long-term strategy is to increase our oil and
natural gas reserves and production while keeping our finding and development
costs and operating costs competitive with our industry peers. We will implement
this strategy through drilling exploratory and development wells from our
inventory of available prospects that we have evaluated for geologic and
mechanical risk and future reserve or resource potential and by making
acquisitions in our core focus area. Our drilling program will contain some
higher risk, higher reserve potential opportunities as well as some lower risk,
lower reserve potential opportunities, in order to achieve a balanced program of
reserve and production growth.

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 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 (the
"Notes"). 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 HHOC
acquisition from the closing date of January 15, 2002. This acquisition has
significantly affected our results of operations and production growth and will
affect the comparability of our historical results of operations with results of
operations from 2001.

On November 1, 2000, we consummated our initial public offering of 5.75
million shares of common stock. On April 16, 2003, we completed the public
offering of approximately 4.2 million shares of our common stock priced at $9.50
per share. The equity offering also included shares offered by our then
principal stockholder, Evercore Capital Partners, L.P. and certain of its
affiliates ("Evercore"), and by Energy Income Fund, L.P. After payment of
underwriting discounts and commissions, the offering generated net proceeds to
us of approximately $38.0 million. After expenses of approximately $0.5 million,
the proceeds were used to repay a portion of outstanding borrowings under our
bank credit facility.

On August 5, 2003, we issued $150 million of 8.75% Senior Notes Due 2010
(the "Senior Notes") in a Rule 144A private offering (the "Debt Offering") which
allows unregistered transactions with qualified institutional and non-U.S.
purchasers. After discounts and commissions and all offering expenses, we
received $145.3 million, which was used to redeem all of our outstanding 11%
Senior Subordinated Notes Due 2009 and to repay substantially all of the
borrowings outstanding under our bank credit facility. The remainder of the net
proceeds has been set aside for general corporate purposes, including
acquisitions. In October 2003, we consummated an exchange offer pursuant to
which we exchanged registered Senior Notes having substantially identical terms
as the Senior Notes for the privately placed Senior Notes.

We amended our bank credit facility in connection with the Debt Offering.
The amendment reduced the borrowing base under our bank credit facility to $60
million upon consummation of the Debt Offering. The

21

borrowing base remains subject to redetermination based on the proved reserves
of our oil and natural gas properties.

During 2003, Evercore, on two occasions exercised a contractual right to
request us to register with the SEC the possible public sale of our common stock
held by it. Subsequent to each of these requests Evercore priced two public
offerings to sell shares of our common stock. These offerings completed the sale
of its interest in our company. We did not sell any shares in either of these
two offerings and did not receive any proceeds from the shares offered by
Evercore.

Our revenue, profitability and future growth rate depend on a number of
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.

We currently have an extensive inventory of drillable prospects in-house,
we are generating more internally and we are being exposed to new opportunities
through relationships with industry partners. Despite our expanded budget in
2004, strong commodity prices, together with growing production volumes, should
enable us to adhere to our policy of funding our exploration and development
expenditures with internally generated cash flow. This strategy allows us to
preserve our strong balance sheet to finance acquisitions. We believe this year
will provide us a number of opportunities to acquire targeted properties within
our focus area.

22

RESULTS OF OPERATIONS

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

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

(1) Net of the effect of hedging transactions, which reduced oil price
realizations by $1.67, $0.51 and $0.10 per Bbl, for 2003, 2002 and 2001,
respectively and reduced gas price realizations by $0.23, $0.18 and $0.05
per Mcf for 2003, 2002 and 2001, respectively.

REVENUES AND NET INCOME

Our oil and natural gas revenues increased to $229.7 million in 2003 from
$134.1 million in 2002. The significant increase for this period is the result
of increased natural gas and oil prices and increased natural gas production due
primarily to new production from 21 wells drilled in 2002 and in the first half
of 2003. These increases were partially offset by natural reservoir declines. In
addition, 2002 volumes were negatively affected by tropical storm activity.

23

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.

We recognized net income of $33.3 million in 2003 compared to net loss of
$8.8 million in 2002. The increase in net income was primarily due to the
increase in oil and natural gas revenues previously discussed and partially
offset by higher operating costs, as discussed below. 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. The
following items had a significant impact on our net income or loss in 2003, 2002
and 2001 and affect the comparability of the results of operations for those
years:

- In January 2003, we adopted Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations" ("Statement 143")
and the effect of adoption on our results of operations and financial
condition included a cumulative effect of adoption income of $2.3
million, net of deferred income taxes of $1.3 million.

- 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 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.

OPERATING EXPENSES

Operating expenses were impacted by the following:

- Lease operating expense increased $2.3 million to $36.7 million in 2003.
This is a result of the addition of production from new fields, whereas
the majority of our new production in the past was primarily from our
large fields with existing infrastructure and low variable cost. Despite
the increase in absolute costs, our operating costs per Boe have
decreased due to the lower fixed costs required for these new fields.

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.

- Taxes, other than on earnings increased $1.1 million to $7.7 million in
2003. This increase was due to the increase in the production volumes and
prices received for our oil and natural gas production on state leases,
primarily at East Bay and Bay Marchand, which is subject to Louisiana
severance taxes. These taxes are expected to fluctuate from period to
period depending on our production volume from state leases and the
commodity prices received.

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.

24

- Exploration expenditures increased $6.7 million to $17.4 million in 2003.
The expense in 2003 is primarily the result of an increase in dry hole
charges to $10.1 million as a result of exploratory wells drilled during
the year which were found to be not commercially productive, as well as
property impairments of $2.8 million, partially offset by a slight
decrease in seismic expenditures and delay rentals to $4.5 million. Our
exploration expenditures, including dry hole charges will vary depending
on the amount of our capital budget dedicated to exploration activities
and the level of success we achieve in exploratory drilling activities.
Although our dry hole costs were higher in 2003, we allocated more
dollars to exploration in 2003 while maintaining a comparable success
rate.

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.

- Depreciation, depletion and amortization increased $17.4 million to $81.9
million in 2003. The increase was due to the increased depreciable asset
base combined with higher production and a shift in the production
contribution from our various fields. Some fields carry a higher
depreciation burden than others, therefore, changes in the location of
our production will directly impact this expense. This expense includes
$5.2 million for the provision of abandonment liabilities for 2003 as
compared to $6.8 million in 2002.

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 provision
of abandonment liabilities as compared to $8.1 million in 2001.

- Other general and administrative expenses increased $4.2 million to $26.7
million in 2003. The increase was primarily due to increased compensation
($5.6 million) and increased insurance ($0.6 million) offset by a 2002
litigation settlement ($2.0 million), which increased general and
administrative expenses during the prior year.

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.

- Non-cash stock-based compensation expense of $1.3 million was recognized
in 2003, an increase of $0.8 million from 2002. This expense has
increased due to additional grants of restricted stock and the granting
of performance share awards to employees.

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.

OTHER INCOME AND EXPENSE

Interest expense increased $3.2 million to $10.2 million in 2003. The
increase was a result of interest expense on the 8.75% Senior Notes issued in
August 2003 partially offset by the interest savings from the redemption of the
11% Notes and the repayment of the bank facility.

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.

25

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

The increase in revenues we experienced in 2003 significantly increased our
cash flows from operations, which totaled $136.7 million in 2003. We intend to
fund our exploration and development expenditures from internally generated cash
flow, which we define as cash flow from operations before consideration of
changes in working capital plus total exploration expenditures. Our cash on hand
at December 31, 2003 was $104.4 million. Our future internally generated cash
flows 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. We may from time to time use the availability of our bank credit
facility to balance working capital needs.

Our bank credit facility, as amended on July 28, 2003, 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 $60
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. At March
1, 2004, we had $0.1 million outstanding and $59.9 million of credit capacity
available under the bank facility. In addition, we pay an annual fee on the
unused portion of the bank credit facility ranging between 0.375% to 0.5% based
on utilization. The bank credit facility contains customary events of default
and various financial covenants, which require us to: (i) maintain a minimum
current ratio of 1.1, (ii) maintain a minimum EBITDAX to interest ratio of 5.00
times, and (iii) maintain a minimum tangible net worth as calculated in
accordance with the agreement. We were in compliance with these covenants at
December 31, 2003.

On August 5, 2003, we issued, $150 million of 8.75% Senior Notes due 2010.
The Senior Notes bear interest at a rate of 8.75% per annum with interest
payable semi-annually on February 1 and August 1, beginning February 1, 2004. We
may redeem the notes at our option, in whole or in part, at any time on or after
August 1, 2007 at a price equal to 100% of the principal amount plus accrued and
unpaid interest, if any, plus a specified premium which decreases yearly from
4.375% in 2007 to 0% in 2009 and thereafter. In addition, at any time prior to
August 1, 2006, we may redeem up to a maximum of 35% of the aggregate principal
amount with the net proceeds of certain equity offerings at a price equal to
108.75% of the principal amount, plus accrued and unpaid interest. The notes are
unsecured obligations and rank equal in right of payment to all existing and
future senior debt, including the bank credit facility, and will rank senior or
equal in right of payment to all existing and future subordinated indebtedness.
The indenture relating to the Senior Notes contains certain restrictions on our
ability to incur additional debt, pay dividends on our common stock, make
investments, create liens on our assets, engage in transactions with our
affiliates, transfer or sell assets and consolidate or merge substantially all
of our assets. The Senior Notes are not subject to any sinking fund
requirements.

Upon closing on the Senior Notes on August 5, 2003, we called our $38.4
million 11% Notes due 2009 for redemption. The redemption of the Notes in
aggregate principal and accrued interest were funded with a portion of the
proceeds received from the Senior Notes and was completed in August 2003. The
Notes were issued on January 15, 2002 as part of the acquisition of HHOC. In
addition, $39.9 million of the proceeds from the Senior Notes were used to
re-pay substantially all of the borrowings under the bank credit facility. As a
result of the issuance of the Senior Notes, our bank credit facility borrowing
base was reduced from $100 million to $60 million requiring a non-cash charge of
$0.3 million for the write-off of the pro rata remaining balance of unamortized
issue costs.

Net cash of $110.1 million used in investing activities in 2003 primarily
included oil and natural gas property capital and exploration expenditures of
$103.1 million and lease acquisitions of $6.0 million. Exploration expenditures
incurred are excluded from operating cash flows and included in investing
activities. During 2003, we completed 23 drilling projects and 33
recompletion/workover projects, 46 of which were

26

successful. During 2002, we completed 17 drilling projects and 27
recompletion/workover projects, 34 of which were successful.

Our 2004 capital exploration and development budget is focused on
exploration, exploitation and development activities on our proved properties
combined with moderate and higher risk exploratory activities on undeveloped
leases and does not include acquisitions. We currently intend to allocate
approximately 60% of our budget on an annual basis on low risk development and
exploitation activities, approximately 25% to moderate risk exploration
opportunities and approximately 15% to higher risk, higher potential exploration
opportunities. Our exploration and development budget for 2004 is currently $125
million. The level of our budget is based on many factors, including results of
our drilling program, oil and natural gas prices, industry conditions,
participation by other working interest 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 2004 capital expenditures.

We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active exploration and
development program. We believe that internally generated cash flows will be
sufficient to meet our capital requirements for at least the next twelve months.
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.

DISCLOSURES ABOUT CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table aggregates the contractual commitments and commercial
obligations that affect our financial condition and liquidity position as of
December 31, 2003:

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

(1) Consists of commitments to purchase seismic related services.

OFF-BALANCE SHEET TRANSACTIONS

We do not maintain any off-balance sheet transactions, arrangements,
obligations or other relationships with unconsolidated entities or others that
are reasonably likely to have a material current or future effect on our
financial condition, changes in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or capital resources.

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

27

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 may modify our
collar to provide full upside participation after a limited non-participation
range. We had the following contracts as of December 31, 2003:

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, 2003 approximated 35% 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.

DISCUSSION OF 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
28

certain of our accounting policies requires a significant number of estimates.
These accounting policies are described below.

- Successful Efforts Method of Accounting -- Oil and natural gas
exploration and production companies choose one of two acceptable
accounting methods, successful-efforts or full cost. The most significant
difference between the two methods relates to the accounting treatment of
drilling costs for unsuccessful exploration wells ("dry holes") and
exploration costs. Under the successful-efforts method, we recognize
exploration costs and dry hole costs as an expense on the income
statement when incurred and capitalize the costs of successful
exploration wells as oil and natural gas properties. Companies that
follow the full cost method capitalize all drilling and exploration costs
including dry hole costs into one pool of total oil and natural gas
property costs.

We use the successful-efforts method because we believe that it more
conservatively reflects, on our balance sheet, the historical costs that
have future value. However, using successful-efforts often causes our
income statement to fluctuate significantly between reporting periods
based on our drilling success or failure during the periods.

It is typical for companies that have an active exploratory drilling
program, as we do, to incur dry hole costs. During the last three years
we have drilled 57 exploration wells, of which 13 were considered dry
holes. Our dry hole costs charged to expense during this period totaled
$29.5 million out of total exploratory drilling costs of $132.8 million.
It is impossible to predict future dry holes; however we expect to
continue to have dry hole costs in the future which will vary depending
on the level and success of our exploratory program.

- Proved Reserve Estimates -- Our independent reserve engineers prepare our
oil and natural gas reserve estimates using guidelines established by the
U.S. Securities and Exchange Commission and generally accepted accounting
principles. The quality and quantity of data, the interpretation of the
data, and the accuracy of mandated economic assumptions combined with the
judgment exercised by the reserve engineers affect the accuracy of the
estimated reserves. In addition, drilling or production results after the
date of the estimate may cause material revisions to the reserve
estimates in subsequent periods. You should not assume that the present
value of the future net cash flow disclosed in this report reflects the
current market value of the oil and natural gas reserves. In accordance
with the U.S. Securities and Exchange Commission's guidelines, we use
prices and costs determined on the date of the estimate and a 10%
discount rate to determine the present value of future net cash flow.
Actual prices and costs may vary significantly, and the discount rate may
or may not be appropriate based on outside economic conditions.

The computation of the standardized measure of discounted future net cash
flows relating to proved oil and natural gas reserves at December 31,
2003 was based on period-end prices of $6.15 per Mcf for natural gas and
$30.88 per barrel for crude oil after adjusting the West Texas
Intermediate posted price per barrel and the Gulf Coast spot market price
per Mmbtu for energy content, quality, transportation fees, and regional
price differentials for each property. We estimated the costs based on
the current year costs incurred for individual properties or similar
properties if a particular property did not have production during the
prior year. While we believe that future costs can be reasonably
estimated, future prices are difficult to estimate since the market
prices are influenced by events beyond our control. Future global
economic and political events will most likely result in significant
fluctuations in future oil prices. In addition, weather conditions can
cause significant fluctuations in natural gas prices.

- Depletion, Depreciation, and Amortization of Oil and Natural Gas
Properties -- We calculate depletion, depreciation, and amortization
expense ("DD&A") using the estimates of proved oil and natural gas
reserves previously discussed in these critical accounting policies. We
segregate the costs for individual or contiguous properties or projects
and record DD&A for these property costs separately using the units of
production method. Material downward revisions in reserves increase the
DD&A per unit and reduce our net income; likewise, material upward
revisions lower the DD&A per unit and increase our net income.

29

- Impairment of Oil and Gas 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.
Because we account for our proved oil and natural gas properties
separately under the successful efforts method of accounting, we assess
our assets for impairment property by property rather than in one pool of
total oil and natural gas property costs. A significant amount of
judgment is involved in performing these evaluations since the amount is
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. We cannot predict the need for,
nor estimate the amount of, impairment charges that may be recorded in
the future.

We base our assessment of possible impairment using our best estimate of
future prices, costs and expected net cash flow generated by a property.
We estimate future prices based on management's expectations and escalate
both the prices and the costs for inflation if appropriate. If these
undiscounted estimates indicate an impairment, we measure the impairment
expense as the difference between the net book value of the asset and its
estimated fair value measured by discounting the future net cash flow
from the property at an appropriate rate. Actual prices, costs, discount
rates, and net cash flow may vary from our estimates.

In 2002, we adopted Statement 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets," ("Statement 144") which superseded
Statement 121 "Accounting for Impairment of Long-Lived Assets." The
Statement addresses financial accounting and reporting for the impairment
or disposal of long-lived assets. The adoption of this statement did not
have a material effect on our balance sheet or income statement in 2002.

We estimate the amount of capitalized costs of unproved properties which
will prove unproductive by amortizing the balance of the unproved
property costs (adjusted by an anticipated rate of future successful
development) over an average lease term. We will transfer the original
cost of an unproved property to proved properties when we find commercial
oil and natural gas reserves sufficient to justify full development of
the property.

- Asset retirement obligation -- We adopted Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" ("Statement 143") on January 1, 2003. We have significant
obligations to plug and abandon oil and natural gas wells and related
equipment as well as to dismantle and abandon facilities at the end of
oil and natural gas production operations. We record the fair value of a
liability for an Asset Retirement Obligation ("ARO") in the period in
which it is incurred and a corresponding increase in the carrying amount
of the related asset. Subsequently, the ARO included in the carrying
amount of the related asset are allocated to expense using the units-of-
production method. In addition, accretion of the discount related to the
ARO liability resulting from the passage of time is reflected as
additional depreciation, depletion and amortization expense in the
Consolidated Statement of Operations.

Inherent in the fair value calculation of the ARO are numerous
assumptions and judgments including the ultimate settlement amounts,
inflation factors, credit adjusted discount rates, timing of settlement,
and changes in the legal, regulatory, environmental and political
environments. To the extent future revisions to these assumptions impact
the present value of the existing ARO liability, a corresponding
adjustment will be required to be made to the oil and natural gas
property balance. This adjustment may then have a positive or negative
impact on the associated depreciation expense and accretion expense
depending on the nature of the revision.

- 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
30

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.

Under the above critical accounting policies our net income can vary
significantly from period to period because events or circumstances which
trigger recognition as an expense for unsuccessful wells or impaired properties
cannot be accurately forecast. In addition, selling prices for our oil and
natural gas fluctuate significantly. Therefore we focus more on cash flow from
operations and on controlling our finding and development, operating,
administration, and financing costs.

NEW ACCOUNTING POLICIES

In November 2002, the Financial Accounting Standards Board ("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 have adopted FIN 45, which did not have
an impact on our financial position, results of operations or cash flows.

In December 2003, the FASB issued FASB Interpretation 46 (Revised December
2003), "Consolidation of Variable Interest Entities," ("FIN 46R") which
addresses how a business enterprise should evaluate whether it has a controlling
financial interest in an entity through means other than voting rights and
accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation
46, "Consolidation of Variable Interest Entities," which was issued in January
2003. We will be required to apply FIN 46R to variable interests in variable
interest entities ("VIEs") no later than March 31, 2004. We have assessed the
impact of FIN 46R, which will not currently have an impact on our financial
position, results of operations or cash flows.

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 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 have adopted Statement 145, which
did not have an impact on our financial position, results of operations or cash
flows.

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 became effective for disposal activities initiated after December
31, 2002. We have adopted Statement 146 which did not have an impact on our
financial positions results of operations or cash flows.

31

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
FASB 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. Disclosures required by this standard are
included in the notes to these consolidated financial statements.

On April 30, 2003, the FASB issued Statement of Financial Accounting
Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" ("Statement 149"). Statement 149 amends and clarifies the
accounting guidance on (1) derivative instruments (including certain derivative
instruments embedded in other contracts) and (2) hedging activities that fall
within the scope of FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("Statement 133"). Statement 149 also amends
certain other existing pronouncements, which will result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting. Statement 149 is
effective (1) for contracts entered into or modified after June 30, 2003, with
certain exceptions, and (2) for hedging relationships designated after June 30,
2003. The guidance is to be applied prospectively. We have adopted Statement
149, which did not have an impact on our financial position, results of
operations or cash flows.

In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity" ("Statement 150"). Statement 150 establishes
standards for how an issuer classifies and measures in its statement of
financial position certain financial instruments with characteristics of both
liabilities and equity. In accordance with the standard, financial instruments
that embody obligations for the issuer are required to be classified as
liabilities. Statement 150 is effective for financial instruments entered into
or modified after May 31, 2003, and otherwise shall be effective at the
beginning of the first interim period beginning after June 15, 2003. We have
adopted the Statement 150, which did not have an impact on our financial
position, the results of operations or cash flows.

Statement of Financial Accounting Standards No. 141, "Business
Combinations," ("Statement 141") and No. 142, "Goodwill and Intangible Assets,"
("Statement 142") became effective for us on July 1, 2001 and January 1, 2002,
respectively. Statement 141 requires all business combinations initiated after
June 30, 2001, to be accounted for using the purchase method. Additionally,
Statement 141 requires companies to disaggregate and report separately from
goodwill certain intangible assets. Statement 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under Statement 142,
goodwill and certain other intangible assets are not amortized, but rather are
reviewed annually for impairment. The appropriate application of Statement 141
and 142 to oil and natural gas mineral rights held under lease and other
contractual arrangements representing the right to extract such reserves is
unclear. Depending on how the accounting and disclosure literature is clarified,
these oil and natural gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves for both
undeveloped and developed leaseholds may be classified separately from oil and
natural gas properties, as intangible assets on our balance sheets. Additional
disclosures required by Statements 141 and 142 would be included in the notes to
financial statements. Historically, we, like many other oil and natural gas
companies, have included these oil and natural gas mineral rights held under
lease and other contractual arrangements representing the right to extract such
reserves as part of the oil and natural gas properties, even after Statements
141 and 142 became effective.

This interpretation of Statements 141 and 142 would affect only our balance
sheet classification of oil and natural gas leaseholds. Our results of
operations and cash flows would not be affected, since these oil and natural gas
mineral rights held under lease and other contractual arrangements representing
the right to extract such reserves would continue to be amortized in accordance
with accounting rules for oil and natural

32

gas companies provided in Statement of Financial Accounting Standards No. 19
"Financial Accounting and Reporting by Oil and Gas Producing Companies."

At December 31, 2003, we had unproved and proved leasehold of approximately
$5.0 million and $100.0 million that would have been classified on the balance
sheet as unproved intangible oil and natural gas properties and intangible
acquired proved leaseholds, respectively, if we applied the interpretation
currently being deliberated by the Emerging Issues Task Force ("EITF"). We will
continue to classify our oil and natural gas leaseholds as oil and natural gas
properties until further guidance is provided.

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. Currently, we do not use
interest rate derivative instruments to manage exposure to interest rate
changes. At December 31, 2003, $0.1 million of our long-term debt had variable
interest rates, while the remaining long-term debt had fixed interest rates,
therefore an increase in the variable interest rate would not have a material
impact on net income.

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, 2003,
we had the following contracts in place:

Our hedged volume as of December 31, 2003 approximated 35% of our estimated
production from proved reserves through the balance of the terms of the
contracts. Had these contracts been terminated at December 31, 2003, we estimate
the loss would have been $3.8 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, 2003, the potential change
in the fair value of commodity derivative instruments assuming a 10% increase in
the underlying commodity price was a $4.1 million increase in the combined
estimated loss.

33

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.

34

GLOSSARY OF OIL AND NATURAL GAS TERMS

"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.

"Mmbbls" One million barrels of oil or other liquid hydrocarbons

"Mmboe" One million barrels of oil equivalent

"Mmbtu" One million British Thermal Units.

"Mmcf" One million cubic feet of natural gas.

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

"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.

"EBITDAX" Net income (loss) before interest expense, income taxes,
depreciation, depletion and amortization, exploration expenditures and
cumulative effect of change in accounting principle.

35

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 auditing standards generally accepted in
the United States of America 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

36

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, 2003 and 2002, 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,
2003. 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, 2003 and 2002, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2003, 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 asset retirement obligations in
2003.

KPMG LLP

New Orleans, Louisiana
February 9, 2004

37

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2003 AND 2002
(IN THOUSANDS, EXCEPT SHARE DATA)

See accompanying notes to consolidated financial statements.
38

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN THOUSANDS, EXCEPT PER SHARE DATA)

See accompanying notes to consolidated financial statements.
39

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.
40

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.
41

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. The Company's future financial condition and results of operations
will depend primarily upon prices received for its oil and natural gas
production and the costs of finding, acquiring, developing and producing
reserves.

(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. The Company's interests in oil and natural gas exploration and
production ventures and partnerships are proportionately consolidated.

(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.

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) ASSET RETIREMENT OBLIGATION

In 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" (Statement 143). Statement 143 requires companies to record the
present value of obligations associated with the retirement of tangible
long-lived assets in the period in which it is incurred. The liability is
capitalized as part of the related long-lived asset's carrying amount. Over
time, accretion of the liability is recognized as an operating expense and the
capitalized cost is depreciated over the expected useful life of the related
asset. The Company's asset retirement obligations relate primarily to the
plugging, dismantlement, removal, site reclamation and similar activities of its
oil and gas properties. The Company adopted 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. Prior to adoption of this statement, such obligations were accrued
ratably over the productive lives of the assets through its depreciation,
depletion and amortization for oil and natural gas properties.

42

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(d) 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.

(e) 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.

(f) 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.

(g) 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. The Company had natural gas
imbalance receivables of $1.7 million and $1.3 million at December 31, 2003 and
2002, respectively and had liabilities of $0.5 million at December 31, 2003 and
2002.

(h) 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, 2003 and 2002, interest-bearing cash equivalents
were approximately $110.4 million and $4.4 million, respectively. Exploration
expenditures incurred are excluded from operating cash flows and included in
investing activities.

(i) 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.
43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

(j) 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). 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 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):

(k) ALLOWANCE FOR DOUBTFUL ACCOUNTS

The Company routinely assesses the recoverability of all material trade and
other receivables to determine their collectibility. Many of the Company's
receivables are from joint interest owners on properties of which the Company is
the operator. Thus, the Company may have the ability to withhold future revenue
disbursements to recover any non-payment of joint interest billings. The
Company's crude oil and natural gas receivables are typically collected within
two months. The Company accrues an allowance on a receivable when, based on the
judgment of management, it is probable that a receivable will not be collected
and the

44

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amount of any allowance may be reasonably estimated. As of December 31, 2003 and
2002, the Company had an allowance for doubtful accounts of $25,960 and $1.4
million, respectively.

(l) 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. Certain accounting policies involve judgments
and uncertainties to such an extent that there is reasonable likelihood that
materially different amounts could have been reported under different
conditions, or if different assumptions had been used. The Company evaluates its
estimates and assumptions on a regular basis. The Company bases its estimates on
historical experience and various other assumptions that are believed to be
reasonable under the circumstances, to form the basis for making judgments about
carrying values of assets and liabilities that are not readily apparent from
other sources. The Company's actual results may differ from these estimates and
assumptions used in preparation of its financial statements. Significant
estimates with regard to these financial statements and related unaudited
disclosures include the estimate of proved oil and natural gas reserve
quantities and the related present value of estimated future net cash flows
there-from disclosed in note 21.

(m) RECLASSIFICATIONS

Certain reclassifications have been made to the prior period financial
statements in order to conform to the classification adopted for reporting in
fiscal 2003.

(3) COMMON STOCK

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. On April
16, 2003, the Company completed the public offering of approximately 6.8 million
shares of its common stock (the Equity Offering), which was priced at $9.50 per
share. The Equity Offering included 4.2 million shares offered by the Company,
1.7 million shares offered by the Company's then principal stockholders,
Evercore Capital Partners L.P. and certain of its affiliates (Evercore), and 0.9
million shares offered by Energy Income Fund, L.P. (EIF). In addition, the
underwriters exercised their option to purchase 1.0 million additional shares to
cover over-allotments, the proceeds from which went to selling shareholders and
not to the Company. After payment of underwriting discounts and commissions, the
offering generated net proceeds to the Company of approximately $38.0 million.
After expenses of approximately $0.5 million, the proceeds were used to repay a
portion of outstanding borrowings under the Company's bank credit facility.

In July 2003, Evercore exercised a contractual right to request us to
register with the SEC for possible public sale 2.5 million shares of common
stock. On August 8, 2003 we were informed by Evercore that it had priced a
public offering of the 2.5 million shares of our common stock at $10.40 per
share. In October 2003, Evercore, again exercised its contractual right to
request the Company to register with the SEC for possible sale of all of
Evercore's remaining approximately 4.5 million shares of common stock. On
November 11, 2003 the Company was informed by Evercore that it had priced a
public offering of all of these remaining shares of the Company's common stock
at $11.75 per share. This offering completed the sale of Evercore's interest in
the Company. The Company did not sell any shares in the offering and did not
receive any proceeds from the shares offered by the selling stockholders.

(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. Diluted earnings per share is computed in the same manner as basic
earnings per share except that the denominator is increased to include

45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the number of additional common shares that could have been outstanding assuming
the exercise of stock options, warrants and convertible preferred stock shares.

The following table reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
the years ended December 31, 2003 and 2001. The diluted loss per share
calculation for the year ended December 31, 2002 produces results that are
anti-dilutive, therefore, the diluted loss per share amount as reported for this
period in the accompanying consolidated statements of operations is the same as
the basic loss per share amount.

(5) SUPPLEMENTAL CASH FLOW INFORMATION

The following is supplemental cash flow information:

46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

On November 17, 1999, the Company issued a warrant to EIF to purchase
928,050 shares of common stock as required by a financing transaction with
Evercore. EIF exercised its option to convert the warrant in January 2001,
receiving 466,245 shares of common stock.

(6) ACQUISITIONS

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 (the Notes), due 2009 (immediately
callable at par), 574,931 shares of common stock with a fair value of
approximately $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 the Company's 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.

In addition, former preferred stockholders of HHOC have the right to
receive contingent consideration. Some of the former stockholders are employees
of the Company, however, any contingent consideration payments are not tied to
continued employment. The contingent consideration is 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
of the acquisition (the Ring-Fenced Properties) exceeds the net present value
discounted at 30%. The potential consideration is determined annually beginning
March 3, 2003 and ending March 1, 2007. The cumulative percentage remitted to
the participants is 20% for March 3, 2003, 30% for March 1, 2004, 35% for March
1, 2005, 40% for March 1, 2006 and 50% for March 1, 2007. The contingent
consideration, if any, may be paid in the Company's common stock or cash at the
Company's option (with a minimum of 20% in cash) and in no event will exceed a
value of $50 million. On March 17, 2003, the Company capitalized, as additional
purchase price, and paid additional consideration of $0.9 million related to the
March 3, 2003 contingent consideration payment date. The Company does not expect
the 2004 contingent consideration payment to exceed $2.5 million. Due to the
uncertainty inherent in estimating the value of future contingent consideration
which includes annual revaluations based upon, among other things, drilling
results from the date of the prior revaluation, and development, operating and
abandonment costs and production revenues (actual historical and future
projected, as contractually defined,

47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

as of each revaluation date) for the Ring-Fenced Properties, total final
consideration will not be determined until March 1, 2007. All additional
contingent consideration will be capitalized as additional purchase price. The
following table summarizes the fair value of the assets acquired and liabilities
assumed at the date of acquisition:

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, 2003
and 2002:

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

(8) ASSET RETIREMENT OBLIGATION

In 2001, the Financial Accounting Standards Board (FASB) issued 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
adopted 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 previously recorded
estimated costs of dismantlement, removal, site restoration and similar
activities as part of its depreciation, depletion and amortization for oil and
natural gas properties and recorded a separate liability for such amounts in
other liabilities. The effect of adopting Statement 143 on the Company's results
of operations and financial condition included 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 of $1.3 million.

48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The pro forma asset retirement obligations would have been $26.0 million at
January 1, 2002 and $36.9 million at December 31, 2002 had the Company adopted
Statement 143 on January 1, 2002. The following pro forma data summarizes the
Company's net loss and net loss per share as if the Company had adopted the
provisions of Statement 143 on January 1, 2002 (in thousands, except per share
amounts):

The following table reconciles the beginning and ending aggregate recorded
amount of the asset retirement obligation for the year ended December 31, 2003
(in thousands):

(9) LONG-TERM DEBT

On August 5, 2003, the Company issued $150 million of 8.75% Senior Notes
Due 2010 (the Senior Notes) in a Rule 144A private offering (the Debt Offering)
which allows unregistered transactions with qualified institutional buyers. In
October 2003, the Company consummated an exchange offer pursuant to which it
exchanged registered Senior Notes having substantially identical terms as the
Senior Notes for the privately placed Senior Notes. After discounts and
commissions and all offering expenses, the Company received $145.3 million,
which was used to redeem all of the outstanding 11% Senior Subordinated Notes
Due 2009 (see note 6) and to repay substantially all of the borrowings
outstanding under the Company's bank credit facility. The remainder of the net
proceeds will be used for general corporate purposes, including acquisitions.

The Senior Notes mature on August 1, 2010 with interest payable each
February 1 and August 1, commencing February 1, 2004. The indenture relating to
the Senior Notes contains certain restrictions on the Company's ability to incur
additional debt, pay dividends on its common stock, make investments, create
liens on its assets, engage in transactions with its affiliates, transfer or
sell assets and consolidate or merge substantially all of its assets. The Senior
Notes are not subject to any sinking fund requirements.

49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On July 28, 2003 the Company amended its bank credit facility in connection
with the Debt Offering. The amendment reduced the borrowing base under the bank
credit facility to $60 million upon consummation of the Debt Offering. The
borrowing base 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. In addition, we pay
an annual fee on the unused portion of the bank credit facility ranging between
0.375% to 0.5% based on utilization. The weighted average interest rate at
December 31, 2003 and 2002 was 4.00% and 3.18%, respectively. The bank credit
facility contains customary events of default and various financial covenants
which required the Company to: (i) maintain a minimum current ratio of 1.1, (ii)
maintain a minimum EBITDAX to interest ratio of 5.00 times, and (iii) maintain a
minimum tangible net worth as calculated in accordance with the agreement. The
Company was in compliance with these covenants at December 31, 2003.

Total long-term debt outstanding at December 31, 2003 and 2002 were as
follows:

Maturities of long-term debt as of December 31, 2003 were as follows (in
thousands):

2004........................................................ $ 99
2005........................................................ 208
2006........................................................ 109
2007........................................................ --
2008........................................................ --
Thereafter.................................................. 150,000
--------
$150,416
========

(10) REDEEMABLE PREFERRED STOCK

In connection with the acquisition of HHOC, in January 2002, 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.

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 2003, 14,184.9 shares of Series D Preferred Stock were converted
into 166,095 shares of common stock and in 2002, 1,445.8 shares of Series D
Preferred Stock were converted into 16,929 shares of common stock.

(11) SIGNIFICANT CUSTOMERS

The Company had oil and natural gas sales to two customers accounting for
approximately 30 percent and 10 percent, respectively, of total oil and natural
gas revenues, excluding the effects of hedging activities, for the year ended
December 31, 2003. 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 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.

(12) 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. Any gains or losses resulting from these hedging transactions are recorded
in other revenue in the statements of operations. 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

51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. In some
hedges we may modify our collar to provide full upside participation after a
limited non-participation range.

The Company had the following hedging contracts as of December 31, 2003:

For the years ended December 31, 2003, 2002 and 2001, hedging activities
reduced oil and gas revenues by $11.5, $5.0 and $3.5 million, respectively.

The following table reconciles the change in accumulated other
comprehensive income for the years ended December 31, 2003 and 2002:

52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Based upon current prices, the Company expects to transfer approximately
$3.8 million of pretax net deferred losses in accumulated other comprehensive
income as of December 31, 2003 to earnings during 2004 when the forecasted
transactions actually occur.

(13) FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values
of financial instruments held by the Company at December 31, 2003 and 2002. 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 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.

53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(14) INCOME TAXES

Components of income tax expense (benefit) for the years ended December 31,
2003, 2002 and 2001 are as follows:

The reasons for the differences between the effective tax rates and the
"expected" corporate federal income tax rate of 34% is as follows:

54

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,
2003 and 2002 are presented below:

At December 31, 2003, the Company had net operating loss carryforwards of
approximately $52.8 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 and, reversal of taxable temporary differences. As a
result, no valuation allowance has been provided.

(15) EMPLOYEE BENEFIT PLANS

The Company has a long term incentive plan authorizing various types of
market and performance based incentive awards which may be granted to officers
and employees. The Amended and Restated 2000 Long Term Stock Incentive Plan (the
Plan) provides for the grant of stock options for which the exercise price, set
at the time of the grant, is not less than the fair market value per share at
the date of grant. The options have a term of 10 years and generally vest over 3
years. The Plan also provides for restricted stock and performance share awards.
The amended plan was approved by stockholders on May 9, 2002 and 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 for all types of awards is
4,800,000.

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. The restricted stock granted became fully vested in
2002. 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 131,754 and 92,990 shares of common stock as restricted
stock awards in 2003 and 2002, respectively, to certain employees and officers.
The restrictions on this stock generally lapse on the second and third
anniversary of the date of grant and require that the employee remain employed
by the Company during the vesting period. The weighted average grant-date fair
value of restricted shares granted in the years ended December 31, 2003 and 2002
was approximately $10.12 and $8.19, respectively.

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company has recognized non-cash compensation expense of $0.8 million,
$0.5 million and $1.7 million in 2003, 2002 and 2001, respectively, related to
the restricted stock and stock option grants. At December 31, 2003, there was
$1.1 million of deferred stock based compensation expense related to the
restricted stock awards, which will be recognized over the remaining vesting
periods.

In 2003, 141,500 performance shares were awarded and 13,333 were forfeited,
leaving 128,167 performance shares outstanding at December 31, 2003. These
shares cliff vest at the end of three years and are based on the attainment of
certain performance goals. The expected fair value of the shares on the vesting
date is charged to expense ratably over the vesting period unless it is
determined that the performance goals will not be met. The Company recognized
non-cash compensation expense of $0.5 million related to these awards in 2003.

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, 2003, 2002 and 2001 are as follows:

A summary of information regarding stock options outstanding at December
31, 2003 is as follows:

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 15,343 and 9,206 shares of common stock in 2003 and 2002 valued at
approximately $175,000 and $84,000, respectively.

(16) COMMITMENTS AND CONTINGENCIES

The Company has operating leases for office space and equipment, which
expire on various dates through 2011. In addition, the Company has agreed to
purchase seismic-related services which expire on various dates through 2005.

Future minimum commitments as of December 31, 2003 under these operating
obligations are as follows (in thousands):

2004........................................................ $ 3,945
2005........................................................ 5,961
2006........................................................ 2,870
2007........................................................ 1,960
2008........................................................ 1,971
Thereafter.................................................. 3,479
-------
$20,186
=======

Rent expense for the years ended December 31, 2003, 2002 and 2001 was $3.7
million, $3.3 million and $1.8 million, respectively.

Commencing January 1, 2002, the Company has been 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.

In February 2003, the Company settled a lawsuit filed in 2001 for $2
million. This settlement is reflected in general and administrative expenses in
2002. 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.

(17) RELATED PARTY

The Company's Chairman, 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 $4.2 million,
$4.0 million and $4.2 million in 2003, 2002 and 2001, 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
2003, 2002 and 2001. The requirement to pay this fee ceased in November 2003
when Evercore's beneficial ownership of the Company's stock became less than

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10%. 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.

Certain officers and their affiliates that held interests prior to the HHOC
transaction continue to be royalty owners in individual properties acquired from
HHOC and operated by the Company.

(18) INTERIM FINANCIAL INFORMATION (UNAUDITED)

The following is a summary of consolidated unaudited interim financial
information for the years ended December 31, 2003 and 2002:

(19) SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In connection with the Debt Offering, discussed above, all of the Company's
current active subsidiaries (the Guarantor Subsidiaries) jointly, severally and
unconditionally guaranteed the payment obligations under the Debt Offering. The
following supplemental financial information sets forth, on a consolidating
basis, the balance sheet, statement of operations and cash flow information for
Energy Partners, Ltd. (Parent Company Only) and for the Guarantor Subsidiaries.
The Company has not presented separate financial statements and other
disclosures concerning the Guarantor Subsidiaries because management has
determined that such information is not material to investors.

The supplemental condensed consolidating financial information has been
prepared pursuant to the rules and regulations for condensed financial
information and does not include all disclosures included in annual financial
statements, although the Company believes that the disclosures made are adequate
to make the information presented not misleading. Certain reclassifications were
made to conform all of the financial information to the financial presentation
on a consolidated basis. The principal eliminating entries eliminate investments
in subsidiaries, intercompany balances and intercompany revenues and expenses.

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2003

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2003

60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2003

(20) NEW ACCOUNTING POLICIES

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 has adopted FIN 45, which did not have an impact on the
financial position, results of operations or cash flows of the Company.

In December 2003, the FASB issued FASB Interpretation 46 (Revised December
2003), "Consolidation of Variable Interest Entities," (FIN 46R) which addresses
how a business enterprise should evaluate whether it has a controlling financial
interest in an entity through means other than voting rights and accordingly
should consolidate the entity. FIN 46R replaces FASB Interpretation 46,
"Consolidation of Variable Interest Entities," which was issued in January 2003.
The Company will be required to apply FIN 46R to variable interests in variable
interest entities (VIEs) no later than March 31, 2004. The Company has assessed
the

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

impact of FIN 46R, which will not currently have an impact on the financial
position, results of operations or cash flows of the Company.

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 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 has adopted Statement 145,
which did not have an impact on the financial position, results of operations or
cash flows 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 became effective for disposal activities initiated after December
31, 2002. The Company adopted Statement 146, which did not have an impact on the
financial position, results of operations or cash flows of the Company.

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. Disclosures required by Statement 148 are
included in these notes to the consolidated financial statements.

On April 30, 2003, the FASB issued Statement of Financial Accounting
Standards No. 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities (Statement 149). Statement 149 amends and clarifies the
accounting guidance on (1) derivative instruments (including certain derivative
instruments embedded in other contracts) and (2) hedging activities that fall
within the scope of FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities (Statement 133). Statement 149 also amends
certain other existing pronouncements, which will result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting. Statement 149 is
effective (1) for contracts entered into or modified after June 30, 2003, with
certain exceptions, and (2) for hedging relationships designated after June 30,
2003. The guidance is to be applied prospectively. The Company has adopted
Statement 149, which did not have an impact on its financial position, results
of operations or cash flows.

In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150, Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity (Statement 150). Statement 150 establishes standards
for how an issuer classifies and measures in its statement of financial position
certain financial instruments with characteristics of both liabilities and
equity. In accordance with the standard, financial instruments that embody
obligations for the issuer are required to be classified as liabilities.
Statement 150 is effective for financial instruments entered into or modified
after May 31, 2003, and otherwise shall be effective at the beginning of the
first interim period beginning after June 15, 2003. The Company has adopted
Statement 150, which did not have an impact on its financial position, results
of operations or cash flows.

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Statement of Financial Accounting Standards No. 141, "Business
Combinations," (Statement 141) and No. 142, "Goodwill and Intangible Assets,"
(Statement 142) became effective for the Company on July 1, 2001 and January 1,
2002, respectively. Statement 141 requires all business combinations initiated
after June 30, 2001, to be accounted for using the purchase method.
Additionally, Statement 141 requires companies to disaggregate and report
separately from goodwill certain intangible assets. Statement 142 establishes
new guidelines for accounting for goodwill and other intangible assets. Under
Statement 142, goodwill and certain other intangible assets are not amortized,
but rather are reviewed annually for impairment. The appropriate application of
Statement 141 and 142 to oil and gas mineral rights held under lease and other
contractual arrangements representing the right to extract such reserves is
unclear. Depending on how the accounting and disclosure literature is clarified,
these oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves for both
undeveloped and developed leaseholds may be classified separately from oil and
gas properties, as intangible assets on the Company's balance sheets. Additional
disclosures required by Statements 141 and 142 would be included in the notes to
financial statements. Historically, the Company, like many other oil and gas
companies, have included these oil and gas mineral rights held under lease and
other contractual arrangements representing the right to extract such reserves
as part of the oil and gas properties, even after Statements 141 and 142 became
effective.

This interpretation of Statements 141 and 142 would affect only the
Company's balance sheet classification of oil and natural gas leaseholds. The
results of operations and cash flows would not be affected, since these oil and
natural gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves would continue to be amortized
in accordance with accounting rules for oil and natural gas companies provided
in Statement of Financial Accounting Standards No. 19 "Financial Accounting and
Reporting by Oil and Gas Producing Companies."

At December 31, 2003, the Company had unproved and proved leasehold of
approximately $5 million and $100 million that would have been classified on the
balance sheet as unproved intangible oil and natural gas properties and
intangible acquired proved leaseholds, respectively, if the Company had applied
the interpretation currently being deliberated by the Emerging Issues Task Force
(EITF). The Company will continue to classify oil and natural gas leaseholds as
oil and natural gas properties until further guidance is provided.

(21) SUPPLEMENTARY OIL AND NATURAL GAS DISCLOSURES -- (UNAUDITED)

Our December 31, 2003 and 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
estimates are based on a reserve report prepared by Netherland, Sewell &
Associates, Inc. Users of this information should be aware that the process of
estimating quantities of "proved" and "proved developed" natural gas and crude
oil reserves is very complex, requiring significant subjective decisions in the
evaluation of all available geological, engineering and economic data for each
reservoir. The data for a given reservoir may also change substantially over
time as a result of numerous factors including, but not limited to, additional
development activity, evolving production history and continual reassessment of
the viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures. Proved reserves
are estimated quantities of natural gas, crude oil and condensate that
geological and 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.
63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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:

64

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, 2003, 2002 and 2001
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.

65

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, 2003, 2002 and 2001 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, 2003 was based on
period-end prices of $6.15 per Mcf for natural gas and $30.88 per barrel for
crude oil. The December 31, 2002 computation 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 25, 2004
were $5.08 per Mmbtu for natural gas and $32.50 per barrel for crude oil before
adjustment for lease quality, transportation fees and price differentials.

66

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Under the supervision and with the participation of certain members of our
management, including the Chief Executive Officer and Chief Financial Officer,
we completed an evaluation of the effectiveness of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities
Exchange Act of 1934, as amended). Based on this evaluation, our Chief Executive
Officer and Chief Financial Officer believe that the disclosure controls and
procedures were effective as of the end of the period covered by this report
with respect to timely communication to them and other members of management
responsible for preparing periodic reports and all material information required
to be disclosed in this report as it relates to our Company and its consolidated
subsidiaries. In October 2003, we implemented a new accounting system that
contains general ledger, payables and receivables, fixed assets and other
related accounting functions. Certain new accounting processes and procedures
were implemented at that time to support the new software. This system change is
the result of our process to evaluate and upgrade or replace systems and related
processes to support our evolving operational needs. During the period from
implementation through December 31, 2003, the new system and supporting
processes were used to record and report our financial results, which are
included in our consolidated totals. Following evaluation, management believes
that the new system has been successfully implemented. Except for the new
accounting system, there was no change in our internal control over financial
reporting during the quarter ended December 31, 2003 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.

Our management, including the Chief Executive Officer and Chief Financial
Officer, does not expect that our disclosure controls and procedures or our
internal controls will prevent all errors and all fraud. A control system, no
matter how well conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system are met. Further,
the design of a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered relative to their
costs. Because of the inherent limitations in all control systems, no evaluation
of controls can provide absolute assurance that all control issues and instances
of fraud, if any, within the company have been detected. These inherent
limitations include the realities that judgments in decision-making can be
faulty, and that breakdowns can occur because of simple error or mistake.
Additionally, controls can be circumvented by the individual acts of some
persons or by collusion of two or more people. The design of any system of
controls also is based in part upon certain assumptions about the likelihood of
future events, and there can be no assurance that any design will succeed in
achieving its stated goals under all potential future conditions; over time,
controls may become inadequate because of changes in conditions, or the degree
of compliance with the policies or procedures may deteriorate. Because of the
inherent limitations in a cost-effective control system, misstatements due to
error or fraud may occur and not be detected. Accordingly, our disclosure
controls and procedures are designed to provide reasonable, not absolute,
assurance that the objectives of our disclosure control system are met and, as
set forth above, our Chief Executive Officer and Chief Financial Officer have
concluded, based on their evaluation as of the end of the period, that our
disclosure controls and procedures were sufficiently effective to provide
reasonable assurance that the objectives of our disclosure control system were
met.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Except as set forth below, 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
13, 2004, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference, and "Part I -- Item 4A. Executive Officers".

Code of Ethics -- The Company has adopted a code of ethics that applies to
all directors and employees, including our chief executive officer, chief
financial officer and controller. Prior to the time of our 2004 Annual
67

Meeting of Stockholders the code of ethics will be posted on our website at
www.eplweb.com. A copy is also available by writing to the Secretary of the
Company at 210 St. Charles Avenue, Suite 3400, New Orleans, Louisiana, 70170.
The Company will post on its website any waiver the Code of Conduct granted to
any of its directors or 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
13, 2004, 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 AND
RELATED STOCKHOLDER MATTERS

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 13, 2004, 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, 2003, with
respect to compensation plans under which our equity securities are authorized
for issuance.

See note 15 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
13, 2004, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

For information required by Item 14 see the definitive Proxy Statement of
Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May
13, 2004, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

68

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, 2003 and 2002

Consolidated Statements of Operations for the years ended December 31,
2003, 2002 and 2001

Consolidated Statements of Changes in Stockholders' Equity for the years
ended December 31, 2003, 2002 and 2001

Consolidated Statements of Cash Flows for the years ended December 31,
2003, 2002 and 2001

Notes to the Consolidated Financial Statements

2. Reports on Form 8-K

On November 12, 2003 the Company filed a current report on Form 8-K,
reporting, under Items 5 and 7, the agreement of Evercore Capital Partners, L.P.
and certain of its affiliates to sell 4,544,572 shares of the Company's common
stock and enclosing the underwriting agreement dated November 10, 2003.

3. Exhibits

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

* Filed herewith

70

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.

71

EXHIBIT INDEX

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

* Filed herewith