ENERGY PARTNERS LTD - 10-K Annual Report

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

FORM 10-K

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. [X]

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, 2004 based on the closing price of such stock as
quoted on the New York Stock Exchange on that date was $411,966,974.

As of February 25, 2005 there were 35,884,066 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 2005 Annual Meeting of Stockholders have been
incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS

2

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. Since our inception in 1998 we have focused on the shallow to moderate
depth waters of the Gulf of Mexico Shelf. With the acquisition of south
Louisiana properties in January 2005, discussed below, we have expanded our
focus area to include the onshore Gulf Coast, which is similar geologically to
the Gulf of Mexico Shelf. We concentrate on this 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, 2004, we had estimated proved reserves
of approximately 149.8 Bcf of natural gas and 28.8 Mmbbls of oil, or an
aggregate of approximately 53.7 Mmboe, with a present value of estimated pre-tax
future net cash flows of $924.1 million, and a standardized measure of
discounted future net cash flows of $667.7 million.

Since our incorporation in January 1998 by Richard A. Bachmann, 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. As we have
grown, we have strengthened our management team, expanded our property base,
reduced our geographic concentration, and moved to a more balanced oil and
natural gas reserves and production profile. We have also expanded our technical
knowledge base through the addition of high quality personnel and geophysical
and geological data.

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, our
website contains our Corporate Governance Guidelines and the charters for our
Audit, Compensation and Nominating Committees. 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.

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ACQUISITION OF SOUTH LOUISIANA RESERVES AND PROSPECTS

On January 20, 2005, we closed the acquisition of properties and reserves
onshore in south Louisiana from Castex Energy 1995, L.P. and Castex Energy, Inc.
("Castex") for $146.0 million in cash, after adjustments for the exercise of
preferential rights by third parties and preliminary closing adjustments. The
properties acquired include nine fields, four of which were producing at the
time of the closing through 14 wells, with estimated proved reserves of 51.2
Bcfe. Also included were interests in 22 exploratory prospects scheduled to be
drilled in 2005. Concurrent with the closing, our bank credit facility borrowing
base was increased to $150 million, of which $60 million was drawn to fund the
acquisition.

This acquisition has taken us into onshore south Louisiana, where our staff
has a wealth of experience. In connection with the acquisition, we also entered
into a two-year agreement with the seller of the properties that defines an area
of mutual interest ("AMI") encompassing over one million acres in which we
intend to jointly explore and develop oil and gas reserves over the next two
years. Both the proved reserves acquired from the seller and the AMI are in the
southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

EXPLORATION AND DEVELOPMENT EXPENDITURES

Our exploration and development expenditures for 2004 totaled $194.2
million inclusive of a $2.2 million contingent consideration payment to former
HHOC stockholders resulting from the January 2002 acquisition of HHOC. For 2005,
we have budgeted exploration and development expenditures of $240 million. This
budget includes exploration and development activities on the newly acquired
properties in south Louisiana as well as exploration and development activities
on our offshore properties. The drilling portfolio, both onshore and offshore,
includes a mixture of lower risk development and exploitation wells, moderate
risk exploration opportunities and higher risk, higher potential exploration
projects. Our 2005 budget does not include any acquisitions of proved reserves
that may occur during the year, including the acquisitions of properties and
reserves to date in 2005.

OUR PROPERTIES

At December 31, 2004, we had interests in 29 producing fields, 5 fields
under development and one field on which drilling operations were then being
conducted, 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 which extends from areas offshore central and western Louisiana to areas
offshore Texas, is comprised of 21 producing fields. Over the last several
years, we have continued to add to our leasehold acreage position in these areas
through federal and state lease sales and trades with industry partners.

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 171 feet. East Bay encompasses nearly 48 square
miles and is comprised primarily of the 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 all of these fields and own an average 96% interest in our acreage
position with our working interest ranging from 18% to 100% and our net revenue
interest varying up to a maximum of 86%. Inclusive of all lease acquisitions,
our leasehold area covers 47,402 gross acres (45,499 net acres).

Our Eastern area operations accounted for approximately 33% of our net
daily production and 15% ($28.2 million) of our capital expenditures during
2004.

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CENTRAL AREA

Our Central area is located approximately 60 miles south of New Orleans in
water depths of 168 feet or less and encompasses nearly 100 square miles. The
focus of our central area operations is the Greater Bay Marchand area. Our key
assets in this area include the South Timbalier 26 and 41 and Bay Marchand
fields as well as currently undeveloped reserves in the South Timbalier 46
field.

In 2003, we drilled our initial discovery well in South Timbalier 41 on
acreage acquired earlier that year in a federal lease sale. Three follow up
wells have been drilled in the field, two of which were brought on production in
early 2005. Development is currently under way for the third well and a fourth
exploratory well is planned for early 2005. This field, in which additional
reserve potential is yet to be tested, represents the most significant discovery
in our history. In addition, through a series of transactions culminating in
early 2000, as of December 31, 2004 we owned a 50% interest in the South
Timbalier 26 field. We serve as operator of this field where we have interests
in 12 producing wells.

On March 8, 2005, we closed the acquisition of the remaining 50% gross
working interest in South Timbalier 26, above approximately 13,000 feet subsea
that we did not already own from Apache Corporation for approximately $21.0
million after preliminary closing adjustments from the effective date of
December 1, 2004. As a result of the acquisition, we now own a 100% gross
working interest in this field. The acquisition expands our interest in our core
Greater Bay Marchand area and gives us additional flexibility in undertaking the
future development of the South Timbalier 26 field.

Our Central area operations accounted for approximately 27% of our net
daily production and 32% ($61.5 million) of capital expenditures during 2004.

WESTERN AREA

The properties in the Western area are located in water depths ranging from
20 to 476 feet with working interests ranging from 17% to 100%. We owned
interests in 27 fields in this area at December 31, 2004, 21 of which were
producing fields with another five under development and one on which drilling
was then in progress.

Our Western area operations accounted for approximately 40% of our net
daily production and 53% ($104.5 million) of our capital expenditures during
2004.

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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, 2004, 2003 and
2002. The December 31, 2004, 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. 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) Approximately 69% of our total proved reserves were proved undeveloped and
proved developed non-producing at December 31, 2004.

(2) Net proved developed non-producing reserves as of December 31, 2004 were
12,976 Mbbls and 72,073 Mmcf.

(3) The December 31, 2004 amount was calculated using a period-end oil price of
$41.84 per barrel and a period-end natural gas price of $6.23 per Mcf, while
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 and
the December 31, 2002 amount was calculated using a period-end oil price of
$29.53 per barrel and a period-end price of $4.83 per Mcf.

(4) 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.

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

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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, 2004:

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

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ACREAGE

The following table sets forth information as of December 31, 2004 relating
to acreage held by us. Developed acreage is assigned to producing wells.

Leases covering 8% of our undeveloped net acreage will expire in 2005,
approximately 28% in 2006, 15% in 2007, 11% in 2008, and 38% in 2009.

WELL ACTIVITY

The following table shows our well activity for the years ended December
31, 2004, 2003 and 2002. 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, mechanics and materialman
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

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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 and a portion of
South Timbalier 41 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
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allowable rates of production from oil and natural gas wells, the regulation of
well spacing, and plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas, and 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.

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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

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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
13

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.
14

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 estimated 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. As of December 31, 2004 and 2003, we had $45.1
million and $40.6 million, respectively, reflected in our consolidated balance
sheets for estimated future abandonment.

ADDITIONAL FACTORS AFFECTING BUSINESS

RISKS RELATING TO THE OIL AND NATURAL GAS INDUSTRY

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

Our future success will depend on the success of our exploration and
production activities. Our oil and natural gas exploration and production
activities are subject to numerous risks beyond our control, including the risk
that drilling will not result in commercially viable oil or natural gas
production. Our decisions to purchase, explore, develop or otherwise exploit
prospects or properties will depend in part on the evaluation of data obtained
through geophysical and geological analyses, production data and engineering
studies, the results of which are often inconclusive or subject to varying
interpretations. 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.

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

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

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

- abnormally pressured formations;

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

- fires and explosions;

- personal injuries and death; and

- natural disasters, especially hurricanes and tropical storms in the Gulf
of Mexico.

Offshore operations are also subject to a variety of operating risks
peculiar to the marine environment, such as capsizing, collisions and damage or
loss from hurricanes, tropical storms or other adverse weather conditions. These
conditions can cause substantial damage to facilities and interrupt production.
15

Any of these risks could adversely affect our ability to conduct operations
or result in substantial losses to our company. We maintain insurance at levels
that we believe are consistent with industry practices and our particular needs,
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 our cash
flow and net income and could reduce or eliminate the funds available for
exploration, exploitation and acquisitions or result in loss of equipment and
properties.

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

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

- changes in 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, ability to finance planned capital
expenditures or ability to pursue acquisitions. Further, oil prices and natural
gas prices do not necessarily move together.

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

The process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant

16

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 our independent petroleum engineers 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 costs on the date of the estimate. Actual future prices and costs may
differ materially from those used in the present-value estimate.

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

Market conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines and
processing facilities owned and operated by third parties. Our failure to obtain
such services on acceptable terms could 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.

RISKS RELATING TO ENERGY PARTNERS, LTD.

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

During the month of December 2004, 32% of our net daily production came
from our East Bay field. If mechanical problems, storms or other events were to
curtail a substantial portion of this production, our cash flow would be
affected adversely. Also, at December 31, 2004, approximately 39% of our proved
reserves were located on this property. In addition, at December 31, 2004
approximately 34% of our proved reserves were located in our Greater Bay
Marchand area. If the actual reserves associated with these properties 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 REGION 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 in the Gulf of Mexico region.
Production from reserves in reservoirs in the Gulf of Mexico region generally
declines more rapidly than from reservoirs in many other producing regions of
the world. As of December 31, 2004, or independent petroleum engineers estimate,
on average, 69% of our total proved reserves will be produced within 5 years. As
a result, our reserve replacement needs from new

17

investments are relatively greater than those of producers who recover lower
percentages of their reserves over a similar time period, such as producers who
have a portion of their reserves outside the Gulf of Mexico in areas where the
rate of reserve production is lower. We may not be able to develop, exploit,
find or acquire additional reserves to sustain our current production levels or
to grow. There can be no assurance that we will be able to grow production at
rates we have experienced in the past. 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.

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

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

- the amount of recoverable reserves and the rates at which those reserves
will be produced;

- 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.

SUBSTANTIAL ACQUISITIONS, DEVELOPMENT PROGRAMS OR OTHER TRANSACTIONS COULD
REQUIRE SIGNIFICANT EXTERNAL CAPITAL AND COULD CHANGE OUR RISK AND PROPERTY
PROFILE.

In order to finance acquisitions of additional producing properties or
finance the development of any discoveries made through any expanded exploratory
program that might be undertaken, 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
18

profile. Additionally, significant acquisitions 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
transactions or to obtain additional external funding on terms acceptable to us.

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

All of our operations are in the Gulf of Mexico region. 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, as a result of increased drilling activity or a
decrease in the supply of equipment, materials and services, 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 ORGANIZATION DOCUMENTS AND UNDER DELAWARE LAW COULD DELAY OR
PREVENT A CHANGE IN CONTROL OF OUR COMPANY, WHICH COULD ADVERSELY AFFECT THE
PRICE OF OUR COMMON STOCK.

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

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

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

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.

THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT US.

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

The exploration and production business is highly competitive, and our
success will depend largely on our ability to attract and retain experienced
geoscientists and other professional staff.

COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY IS INTENSE, WHICH MAY
ADVERSELY AFFECT US.

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
19

able to compete successfully in the future in acquiring prospective reserves,
developing reserves, marketing hydrocarbons, attracting and retaining quality
personnel and raising additional capital. If we are unable to compete
successfully in these areas in the future, our future revenues and growth may be
diminished or restricted.

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
provision 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 Global Trading
("ChevronTexaco") and Shell. Currently, the 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 2004, Shell accounted for approximately 22 percent, Dreyfus 14
percent and ChevronTexaco 13 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, 2004, we had 151 full-time employees, including 42
geoscientists, engineers and technicians and 48 field personnel. Our employees
are not represented by any labor union. We consider relations with our employees
to be satisfactory and we have never experienced a work stoppage or strike.

ITEM 3. LEGAL PROCEEDINGS

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

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:

20

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 has also
been nominated to become a director of Trico Marine Services, Inc.

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 35 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. Subsequent to the year
ended December 31, 2004 Ms. Baer announced her plan to retire in April 2005. Her
successor, David R. Looney, began service in February 2005 and will become our
new chief financial officer following their transition period and his
appointment by our Board of Directors.

Phillip A. Gobe joined us in December 2004 as chief operating officer. Mr.
Gobe has over 28 years of energy industry experience and was with Nuevo Energy
Company as chief operating officer from February 2001 until its acquisition by
Plains Exploration & Production Company in May 2004. Mr. Gobe's primary
responsibilities were managing Nuevo's domestic and international exploitation
and exploration operations. Prior to his position with Nuevo, Mr. Gobe had been
the Senior Vice President of Production for Vastar Resources, Inc. since 1997.
From 1976 to 1997, Mr. Gobe worked for Atlantic Richfield Company and its
subsidiaries in positions of increasing responsibility, primarily in the Gulf of
Mexico and Alaska.

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.

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.

21

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, 2005 the last reported sale price of our common stock on
the New York Stock Exchange was $25.65 per share.

As of February 25, 2005 there were approximately 100 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.

22

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 $3.4
million, $3.5 million and $3.3 million from net income (loss) for the years
ended December 31, 2004, 2003 and 2002, respectively; and by subtracting
preferred stock dividends and accretion of issuance costs of $6.7 million
for the year ended December 31, 2000.

23

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 in 2004 were concentrated in the shallow to moderate depth waters of
the Gulf of Mexico Shelf. In January 2005 we extended our operations into the
Gulf Coast onshore region through an acquisition of properties in South
Louisiana.

In 2004, we achieved another year of growth and reported the best year on a
revenue and net income as well as per-share basis over our seven-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, including 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 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. ("EIF"). 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.

In January 2002 we acquired HHOC. In addition to other consideration paid,
former preferred stockholders of HHOC have the right to receive contingent
consideration based upon a percentage of the amount by which the before tax net
present value of proved reserves related, in general, to exploratory prospect
acreage held by HHOC as of the closing date exceeds a net present value
discounted at 30%. The contingent consideration may be paid in the Company's
common stock or cash at the Company's option (with a minimum of 20% paid in cash
for each payment) and in no event will exceed a value of $50 million. Due to the
uncertainty inherent in estimating the value of the contingent consideration,
total final consideration will not be determined until March 1, 2007. The
contingent consideration paid will be capitalized as additional purchase price.

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 was 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.

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
24

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.

On July 16, 2004, we filed a universal shelf registration statement which
allowed us to issue an aggregate of $300 million in common stock, preferred
stock, senior debt and subordinated debt in one or more separate offerings with
the size, price and terms to be determined at the time of the sale. On November
10, 2004 we sold approximately 3.5 million shares of our common stock to the
public pursuant to this shelf registration statement, leaving us with the
ability to issue an additional $239.6 million of securities under the shelf
registration statement. Concurrent with this offering, we entered into a stock
purchase agreement with EIF in which we purchased approximately 3.5 million
shares of common stock owned by EIF at a price per share equal to the net
proceeds per share received in the offering, before expenses. We did not retain
any of the proceeds from the offering and the shares are now held as treasury
shares, at cost. We have no immediate plans to enter into any additional
transactions under this registration statement, but plan to use the proceeds of
any future offering under this registration statement for general corporate
purposes, which may include debt repayment, acquisitions, expansion and working
capital.

On August 3, 2004 we amended and extended to August 3, 2008 our bank credit
facility. Under the amendment our initial borrowing base remained $60 million.
The borrowing base was increased to $150 million at the time of our purchase of
south Louisiana properties and reserves in January 2005. The borrowing base will
remain subject to redetermination based on the proved reserves of the oil and
natural gas properties that serve as collateral for the bank credit facility.

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
2005, 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 and other capital
intensive projects that might result from our exploration and development
activities. In addition to the south Louisiana property acquisition already
completed in 2005, we believe this year will provide us a number of
opportunities to acquire targeted properties, including those within our focus
area.

25

RESULTS OF OPERATIONS

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

REVENUES AND NET INCOME

Our oil and natural gas revenues increased to $294.5 million in 2004 from
$229.7 million in 2003. In 2004, the oil and natural gas industry experienced
record high oil prices as well as sustained high natural gas

26

prices. The increase in revenue for this period is the result of these
significantly increased natural gas and oil prices combined with increased
production resulting primarily from the commencement of production from 20 new
wells brought on production since year end 2003, 16 of which were natural gas.
These increases were partially offset by natural reservoir declines. In
addition, volumes were negatively affected by Hurricane Ivan and Tropical Storm
Matthew.

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.

We recognized net income of $46.4 million in 2004 compared to net income of
$33.3 million in 2003. 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 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. The following items had a significant impact on our net income
or loss in 2004, 2003 and 2002 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.

OPERATING EXPENSES

Operating expenses were impacted by the following:

- Lease operating expense increased $3.9 million to $40.6 million in 2004.
This is a result of the addition of production from new fields and $1.0
million related to the retained loss portion of repairs due to Hurricane
Ivan.

Lease operating expense increased $2.3 million to $36.7 million in 2003.
This was 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 decreased due
to the lower fixed costs required for these new fields.

- Taxes, other than on earnings increased $1.6 million to $9.3 million in
2004. This increase was due to the increase in commodity prices received
for our oil and natural gas production on state leases, primarily at East
Bay and Bay Marchand, which are subject to Louisiana severance taxes.
These taxes are expected to fluctuate from period to period depending on
our production volumes from state leases and the commodity prices
received.

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.

- Exploration expenditures increased $18.5 million to $35.9 million in
2004. The expense in 2004 is primarily the result of an increase in dry
hole charges of $10.9 million to $21.0 million as a result of exploratory
wells drilled during the year which were found to be noncommercial, as
well as property impairments of $6.9 million at our East Cameron 378
field and seismic expenditures and delay rentals which increased $3.5
million to $8.0 million. Our exploration expenditures, including dry hole
charges will vary depending on the amount of our capital budget dedicated
to exploration activities and the
27

level of success we achieve in exploratory drilling activities. Although
our dry hole costs were higher in 2004, we allocated more dollars to
exploration in 2004 while maintaining a comparable success rate.

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 noncommercial, 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. Although our dry
hole costs were higher in 2003, we allocated more dollars to exploration
in 2003 while maintaining a comparable success rate.

- Depreciation, depletion and amortization increased $10.5 million to $92.4
million in 2004. 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
$6.6 million of amortization for our asset retirement obligation for 2004
as compared to $5.2 million in 2003.

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. This expense includes $5.2 million
of amortization for our asset retirement obligation for 2003 as compared
to $6.8 million in 2002.

- Other general and administrative expenses increased $1.2 million to $27.9
million in 2004. The increase was primarily due to increased consulting
costs ($1.9 million), of which $0.4 million was increased costs paid to
our internal audit service provider and external auditors to implement
the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. The
remainder included increased human resources, land and engineering
consulting costs. This was offset by decreased casualty insurance ($0.4
million) and decreased technology costs ($0.2 million).

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.

- Non-cash stock-based compensation expense of $3.1 million was recognized
in 2004, an increase of $1.8 million from 2003. This expense has
increased due to additional grants of restricted shares and performance
share awards to employees. The level of expense for these awards is also
affected by the increased stock price in 2004.

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 shares and the granting of
performance share awards to employees.

OTHER INCOME AND EXPENSE

Interest expense increased $4.2 million to $14.4 million in 2004. 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 in 2003.

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.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

The increase in revenues we experienced in 2004 increased our cash flows
from operations, which totaled $165.1 million. We intend to fund our exploration
and development expenditures from internally generated cash flows, which we
define as cash flows from operations before consideration of changes in working
capital
28

plus total exploration expenditures. Our cash on hand at December 31, 2004 was
$93.5 million, substantially all of which was used in the purchase of the south
Louisiana properties in January 2005. 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 August 3, 2004, consists of a
revolving line of credit with a group of banks available through August 3, 2008
(the "bank credit facility"). The bank credit facility had a borrowing base of
$60 million. The borrowing base was increased to $150 million at the time of our
purchase of south Louisiana properties and reserves in January 2005. The bank
credit facility is subject to redetermination based on the proved reserves of
the oil and natural gas properties that serve as collateral for the bank credit
facility as set out in the reserve report delivered to the banks each April 1
and October 1. The bank credit 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 credit
facility. The spread can range from 1.25% to 2.00% above LIBOR and 0% to 0.75%
above prime. The borrowing base under the bank credit facility is secured by
substantially all of our assets. We used our bank credit facility to fund a
portion of the purchase of the south Louisiana properties in January 2005 and
the acquisition of the additional interest in South Timbalier 26 in March 2005.
As a result at March 8, 2005, we had $70.0 million outstanding and $80.0 million
of credit capacity available under the bank credit 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 1.0 as defined in our bank credit facility
agreement, and (ii) maintain a minimum EBITDAX to interest ratio of 3.5 times.
We were in compliance with these covenants as of December 31, 2004.

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 was 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 financing 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 $176.7 million used in investing activities in 2004 primarily
included oil and natural gas property capital and exploration expenditures of
$163.0 million, lease acquisitions of $6.6 million and a deposit of $5.0 million
paid for the January 2005 purchase of south Louisiana reserves and prospects
from Castex. Exploration expenditures incurred are excluded from operating cash
flows and included in investing activities. During 2004, we completed 31
drilling projects and 21 recompletion/workover projects, 41 of which were

29

successful. During 2003, we completed 23 drilling projects and 33
recompletion/workover projects, 46 of which were successful.

Our 2005 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, including the acquisitions of
properties and reserves to date in 2005. We currently intend to allocate
approximately 55% of our budget on low risk development and exploitation
activities, approximately 30% to moderate risk exploration opportunities and
approximately 15% to higher risk, higher potential exploration opportunities.
Our exploration and development budget for 2005 is currently $240 million,
inclusive of expected expenditures on the properties acquired in January 2005.
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 2005 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, 2004:

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

(1) At December 31, 2004 there was no outstanding debt with variable interest
rates.

(2) 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

30

upside price participation. Our hedges are benchmarked to the New York
Mercantile Exchange ("NYMEX") West Texas Intermediate crude oil contract and
Henry Hub natural gas contracts. With a financially-settled swap, the
counterparty is required to make a payment to us if the settlement price for any
settlement period is below the hedged price for the transaction, and we are
required to make a payment to the counterparty if the settlement price for any
settlement period is above the hedged price for the transaction. With a
zero-cost collar, the counterparty is required to make a payment to us if the
settlement price for any settlement period is below the floor price of the
collar, and we are required to make a payment to the counterparty if the
settlement price for any settlement period is above the cap price of the collar.
In some hedges, we may modify our collar to provide full upside participation
after a limited non-participation range. We had the following contracts as of
December 31, 2004:

Subsequent to December 31, 2004, we entered into the following contracts:

Accounting and reporting standards require 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 the forecasted transaction is settled,
when the resulting gains and losses will be recorded in earnings. Hedge
ineffectiveness is measured at least quarterly based on the changes in fair
value between the derivative contract and the hedged item. Any change in fair
value resulting from ineffectiveness is charged currently to other revenue.

Our hedged volume as of December 31, 2004 approximated 22% 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.

31

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 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 as a 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 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 61 exploration wells, of which 12 were considered dry holes.
Our dry hole costs charged to expense during this period totaled $36.9
million out of total exploratory drilling costs of $200.5 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 amount
of our capital dedicated to exploration activities and on the level of
success of our exploratory program.

- Proved Reserve Estimates -- Evaluations of oil and natural gas reserves
are important to the effective management of our producing assets. They
are integral to making investment decisions and are also used as a basis
of calculating the units of production rates for depletion, depreciation
and amortization and evaluating capitalized costs for impairment. Proved
reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made.

Our independent reserve engineers prepare our oil and natural gas reserve
estimates using guidelines established by the U.S. Securities and Exchange
Commission and U.S. 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.

At December 31, 2004, proved oil and natural gas reserves were 53.7
million barrels of oil-equivalent ("Mmboe"). Approximately 69 percent of
our proved reserves are classified as either proved undeveloped or proved
developed non-producing reserves. Most of our proved developed non-
producing reserves are "behind pipe" and will be produced after depletion
of another horizon in the same well. Approximately 22 percent of total
proved reserves are categorized as proved undeveloped reserves. As of
December 31, 2004, 69 percent of our proved undeveloped reserves were
under development and expected to become proved developed within one year.

One 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 costs incurred and

32

prices received in the future 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, 2004
was based on period-end prices of $6.23 per Mcf for natural gas and $41.84
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.

- 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. The units of production method is calculated as the
ratio of (1) actual volumes produced to (2) total proved developed
reserves (those proved reserves recoverable through existing wells with
existing equipment and operating methods) applied to (3) asset cost. The
volumes produced and asset cost are known, and while proved developed
reserves are reasonably certain, they are based on estimates that are
subject to some variability. This variability can result in net upward or
downward revisions of proved developed reserves in existing fields, as
more information becomes available through research and production and as
a result of changes in economic condition. Our revisions over the past
three years, in each case either positive or negative have been less than
5% of total proved reserves on a barrel of oil equivalent basis. While
the revisions we have made in the past are an indicator of variability,
they have had a minimal impact on the units of production rates because
they have been low compared to our reserve base. Actual historical
revisions are not necessarily indicative of future variability.

- 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 may not be recoverable.
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 reserve volumes, or other changes to
contracts, environmental regulations or tax laws. In general, we do not
view temporarily low oil or natural gas prices as a triggering event for
conducting impairment tests. The markets for crude oil and natural gas
have a history of significant price volatility. Although prices will
occasionally drop precipitously, industry prices over the long-term are
driven by market supply and demand. Accordingly, any impairment tests
that we perform make use of our long-term price assumptions for the crude
oil and natural gas markets.

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. An estimate as to the
sensitivity to earnings resulting from impairment reviews and impairment
calculations is not practicable, given the broad range in the cost
33

structure of our oil and natural gas assets and the number of assumptions
involved in the estimates. That is, favorable changes to some assumptions
may avoid the need to impair any assets, whereas unfavorable changes might
cause some assets to become impaired but not others. We recognized
impairment expense of $6.9 million, $2.8 million and none in the years
ending December 31, 2004, 2003 and 2002. The impairment in 2004 consisted
of one field which incurred significant capital costs in excess of those
anticipated. Two fields were fully impaired in 2003 due to mechanical
problems.

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. If we do not find commercial oil and natural gas reserves, the
related unamortized capitalized costs will be charged to earnings when the
determination is made.

- 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 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. 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 market prices
change, 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.
34

NEW ACCOUNTING POLICIES

In November 2004, the FASB issued Statement of Financial Accounting
Standards No. 151 "Inventory Costs, an amendment of ARB No. 43, Chapter 4"
("Statement 151"). The amendments made by Statement 151 clarify that abnormal
amounts of idle facility expense, freight, handling costs, and wasted materials
(spoilage) should be recognized as current-period charges and require the
allocation of fixed production overheads to inventory based on the normal
capacity of the production facilities. The guidance is effective for inventory
costs incurred during fiscal years beginning after June 15, 2005. Earlier
application is permitted for inventory costs incurred during fiscal years
beginning after November 23, 2004. Our assessment of the provisions of Statement
151 is that it is not expected to have an impact on our financial position,
results of operations or cash flows.

In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 152 "Accounting for Real Estate Time-Sharing Transactions -- An
Amendment to FASB Statements No. 66 and 67" ("Statement No. 152"). Statement 152
amends FASB Statement No. 66, "Accounting for Sales of Real Estate," to
reference the financial accounting and reporting guidance for real estate
time-sharing transactions that is provided in AICPA Statement of Position (SOP)
04-2, "Accounting for Real Estate Time-Sharing Transactions." Statement 152 also
amends FASB Statement No. 67, "Accounting for Costs and Initial Rental
Operations of Real Estate Projects," to state that the guidance for (a)
incidental operations and (b) costs incurred to sell real estate projects does
not apply to real estate time-sharing transactions. The accounting for those
operations and costs is subject to the guidance in SOP 04-2. Statement 152 is
effective for financial statements for fiscal years beginning after June 15,
2005. Our assessment of the provisions of Statement 152 is that it is not
expected to have an impact on our financial position, results of operations or
cash flows.

In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 153 "Exchanges of Non-monetary assets -- an amendment of APB
Opinion No. 29" ("Statement 153"). Statement 153 amends Accounting Principles
Board ("APB") Opinion 29 to eliminate the exception for nonmonetary exchanges of
similar productive assets and replaces it with a general exception for exchanges
of nonmonetary assets that do not have commercial substance. A nonmonetary
exchange has commercial substance if the future cash flows of the entity are
expected to change significantly as a result of the exchange. Statement 153 does
not apply to a pooling of assets in a joint undertaking intended to fund,
develop, or produce oil or natural gas from a particular property or group of
properties. The provisions of Statement 153 shall be effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early
adoption is permitted and the provisions of Statement 153 should be applied
prospectively. Our assessment of the provisions of Statement 153 is that it is
not expected to have an impact on our financial position, results of operations
or cash flows.

In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 123-Revised 2004, "Share-Based Payment," ("Statement 123R"). This
is a revision of Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation", and supersedes APB No. 25,
"Accounting for Stock Issued to Employees." We currently account for stock-based
compensation under the provisions of APB 25. Under Statement 123R, we will be
required to measure the cost of employee services received in exchange for
stock, based on the grant-date fair value (with limited exceptions). That cost
will be recognized as expense over the period during which an employee is
required to provide service in exchange for the award (usually the vesting
period). The fair value will be estimated using an option-pricing model. Excess
tax benefits, as defined in Statement 123R, will be recognized as an addition to
paid-in capital. This is effective as of the beginning of the first interim or
annual reporting period that begins after June 15, 2005. We are currently in the
process of evaluating the impact of Statement 123R on our financial statements,
including different option-pricing models. Note (2)(j) of the Notes to
Consolidated Financial Statements illustrates the current effect on net income
and earnings per share if we had applied the fair value recognition provisions
of Statement 123.

35

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, 2004, none of our outstanding long-term debt had
variable 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, 2004,
we had the following contracts in place:

Subsequent to December 31, 2004, we entered into the following contracts:

Our hedged volume as of December 31, 2004 approximated 22% of our estimated
production from proved reserves through the balance of the terms of the
contracts. Had these contracts been terminated at December 31, 2004, we estimate
the loss would have been $1.7 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, 2004 and 2003, the
potential change in the fair value of commodity derivative instruments assuming
a 10% increase in the underlying commodity price was a $2.4 million and $4.1
million increase in the combined estimated loss, respectively.

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.

36

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.

"proved undeveloped reserves" Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.

"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.

37

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To the Board of Directors and Stockholders
Energy Partners, Ltd.

Our management is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Exchange
Act Rule 13a-15(f). Our internal control system was designed to provide
reasonable assurance to the Company's management and Board of Directors
regarding the reliability of financial reporting and the presentation of
financial statements for external purposes in accordance with U.S. generally
accepted accounting principles. Under the supervision and with the participation
of our management, we conducted an evaluation of the effectiveness of our
internal control over financial reporting based on the framework in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).

Based on our evaluation under the COSO framework, our management concluded
that our internal control over financial reporting was effective as of December
31, 2004. No matter how well designed, there are inherent limitations in all
systems of internal control. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate. Our management's assessment of the effectiveness of our internal
control over financial reporting as of December 31, 2004 has been audited by
KPMG LLP, an independent registered public accounting firm, as stated in their
report which is included herein, which expresses unqualified opinions on
management's assessment and on the effectiveness of our internal control over
financial reporting as of December 31, 2004.

/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

38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM --
INTERNAL CONTROL OVER FINANCIAL REPORTING

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

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting, that Energy
Partners, Ltd. maintained effective internal control over financial reporting as
of December 31, 2004, based on criteria established in Internal Control --
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Energy Partners, Ltd.'s management is responsible
for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on management's assessment and an
opinion on the effectiveness of the Company's internal control over financial
reporting based on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.

A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Energy Partners, Ltd.
maintained effective internal control over financial reporting as of December
31, 2004, is fairly stated, in all material respects, based on criteria
established in Internal Control -- Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our
opinion, Energy Partners, Ltd. maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2004, based on
criteria established in Internal Control -- Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO).

39

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of Energy Partners, Ltd. and subsidiaries as of December 31, 2004 and
2003, 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, 2004. In connection with our audits of the
consolidated financial statements, we also have audited the accompanying
financial statement schedule, "Valuation and Qualifying Accounts," for the years
ended December 31, 2004, 2003, and 2002. Our report dated March 13, 2005
expressed an unqualified opinion on those consolidated financial statements and
schedule.

/s/ KPMG LLP

New Orleans, Louisiana
March 13, 2005

40

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM --
CONSOLIDATED FINANCIAL STATEMENTS

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, 2004 and 2003, and the
related consolidated statement of operations, changes in stockholders' equity,
and cash flows for each of the years in the three-year period ended December 31,
2004. In connection with our audits of the consolidated financial statements, we
also have audited the accompanying financial statement schedule, "Valuation and
Qualifying Accounts," for the years ended December 31, 2004, 2003, and 2002.
These consolidated financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements and financial statement
schedule based on our audits.

We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the 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, 2004 and 2003, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2004, in conformity with U.S. generally
accepted accounting principles. Also, in our opinion, the related financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.

As discussed in note 2 to the consolidated financial statements, the
Company changed their method of accounting for asset retirement obligations in
2003.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of Energy
Partners, Ltd.'s internal control over financial reporting as of December 31,
2004, based on criteria established in Internal Control -- Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO), and our report dated March 13, 2005, expressed an unqualified opinion on
management's assessment of, and the effective operation of, internal control
over financial reporting.

/s/ KPMG LLP

New Orleans, Louisiana
March 13, 2005

41

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2004 AND 2003
(IN THOUSANDS, EXCEPT SHARE DATA)

See accompanying notes to consolidated financial statements.
42

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(IN THOUSANDS, EXCEPT PER SHARE DATA)

See accompanying notes to consolidated financial statements.
43

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.
44

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.
45

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 as well as the contiguous onshore gulf coast region. 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. Exploratory
drilling costs are initially capitalized, but charged to expense if and when the
well is determined not to have found reserves in commercial quantities. Such
determination does not exceed one year from completion of drilling. The Company
does not currently drill in areas that require major capital expenditures before
production can begin. Geological and geophysical costs are charged to expense as
incurred.

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 assesses the impairment of capitalized costs of proved oil and
natural gas properties when circumstances indicate that the carrying value may
not be recoverable. 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 reserve volumes, or other changes
to contracts, environmental regulations or tax laws. The calculation is
performed 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
46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

(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 debt financing are deferred and are 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
conversion of convertible preferred stock shares, the exercise of warrants and
stock options and the potential shares associated with restricted share units
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 $1.4 million and $1.7 million at December 31, 2004 and
2003, respectively and had liabilities of $0.5 million at December 31, 2004 and
2003.

(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, 2004 and 2003, interest-bearing cash equivalents
were approximately $99.9 million and $110.4 million, respectively. Expenditures
for exploratory dry holes 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. 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
47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 the forecasted transaction is
settled, when the resulting gains and losses will be recorded in earnings. Hedge
ineffectiveness is measured at least quarterly based on the changes in fair
value between the derivative contract and the hedged item. Any change in fair
value resulting from ineffectiveness, will be charged currently to other
revenue.

(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) permit the continued
use of the intrinsic value-based method prescribed by Opinion No. 25, but
require 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:

(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

48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 amount of any allowance may be
reasonably estimated. As of December 31, 2004 and 2003, the Company had an
allowance for doubtful accounts of none and $25,960, 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 uses 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
therefrom disclosed in note 22.

(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 2004.

(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 the Company
to register with the SEC for possible public sale 2.5 million shares of common
stock. On August 8, 2003 the Company was informed by Evercore that it had priced
a public offering of the 2.5 million shares of 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 either of these offerings and did not receive
any proceeds from the shares offered by the selling stockholders.

49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On July 16, 2004 the Company filed a universal shelf registration statement
which allows the Company to issue an aggregate of $300 million in common stock,
preferred stock, senior debt and subordinated debt in one or more separate
offerings with the size, price and terms to be determined at the time of the
sale. On November 10, 2004 the Company sold approximately 3.5 million shares of
its common stock to the public pursuant to this shelf registration statement
leaving us with the ability to issue an additional $239.6 million of securities
under the shelf registration statement. Concurrent with this offering, the
Company entered into a stock purchase agreement with EIF in which it purchased
approximately 3.5 million shares of common stock owned by EIF at a price per
share equal to the net proceeds per share received in the offering, before
expenses. The Company therefore did not retain any of the proceeds from this
offering and the stock has been recorded as treasury stock on the consolidated
balance sheet at cost. The Company has no immediate plans to enter into any
additional transactions under this registration statement, but plans to use the
proceeds for general corporate purposes, which may include debt repayment,
acquisitions, expansion and working capital.

(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 the
number of additional common shares that could have been outstanding assuming the
conversion of convertible preferred stock shares, and the exercise of warrants
and stock options and the potential shares associated with restricted share
units that would have a dilutive effect on earnings per share.

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, 2004 and 2003. 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.

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(5) SUPPLEMENTAL CASH FLOW INFORMATION

The following is supplemental cash flow information:

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

(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 strengthened its management team, expanded its exploration opportunities
and achieved a reserve portfolio and production profile that was 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 reflect 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 had a strike price of $9.00 and three
million had 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 became
exercisable beginning January 15, 2003 and expiring on January 15, 2007. At
December 31, 2004 there were 769,651 warrants outstanding with a strike price of
$9.00 per share and 2,683,153 warrants outstanding with a strike price of $11.00
per share. 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 from March
3, 2003 until March 1, 2007. The cumulative percentage remitted to the
participants was 20% for the March 3, 2003 and 30% for the March 1, 2004
determination dates and is 35% for the March 1, 2005, 40% for the March 1, 2006
and 50% for the March 1, 2007 determination dates. 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 15, 2004 and March 17, 2003, the

51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company capitalized, as additional purchase price, and paid additional
consideration in cash, of $2.2 million and $0.9 million related to the March 1,
2004 and the March 3, 2003 contingent consideration determination dates,
respectively. The Company does not expect the 2005 contingent consideration
payment to exceed $1.0 million. Due to the uncertainty inherent in estimating
the value of future contingent consideration which includes annual valuations
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, 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 in 2002.

(7) PROPERTY AND EQUIPMENT

The following is a summary of property and equipment at December 31, 2004
and 2003:

We analyze proved properties for impairment based on the proved reserves as
determined by our independent reserve engineers. We recognized impairment
expense of $6.9 million, $2.8 million and none in the years ending December 31,
2004, 2003 and 2002, respectively. The impairment expenses were related to our
East Cameron 378 field in 2004 and our Ship Shoal 133 and West Cameron 149
fields in 2003.

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 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
52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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:

The following table reconciles the beginning and ending aggregate recorded
amount of the asset retirement obligation for the year ended December 31, 2004:

(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

53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. In
January 2005, the remainder of the net proceeds were used to purchase properties
in south Louisiana as discussed in note 21.

The Senior Notes mature on August 1, 2010 with interest payable each
February 1 and August 1, commencing February 1, 2004. The Company may redeem the
notes at its 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, the Company 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 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.

On August 3, 2004 the Company amended and extended to August 3, 2008 its
bank credit facility. Under the amendment the initial borrowing base remained
$60 million. The borrowing base was increased to $150 million at the time of our
purchase of south Louisiana properties and reserves in January 2005 (see note
21). The borrowing base is subject to redetermination based on the proved
reserves of the oil and natural gas properties that serve as collateral for the
bank credit facility as set out in the reserve report delivered to the banks
each April 1 and October 1. The bank credit 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 the Company's
utilization of the bank credit facility. The spread can range from 1.25% to
2.00% above LIBOR and 0% to 0.75% above prime. The borrowing base under the bank
credit facility is secured by substantially all of the assets of the Company. In
addition, the Company pays 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 the Company to: (i) maintain a minimum current ratio of
1.0 as defined in the bank credit facility, and (ii) maintain a minimum EBITDAX
to interest ratio of 3.5 times. The Company was in compliance with its bank
facility covenants as of December 31, 2004.

Total long-term debt outstanding at December 31, 2004 and 2003 was as
follows:

54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Maturities of long-term debt as of December 31, 2004 were as follows (in
thousands):

2005........................................................ $ 108
2006........................................................ 109
2007........................................................ --
2008........................................................ --
2009........................................................ --
Thereafter.................................................. 150,000
--------
$150,217
========

(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.

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 2004, 23,676.74 shares of Series D Preferred Stock were
converted into 277,240 shares of common stock and in 2003, 14,184.9 shares of
Series D Preferred Stock were converted into 166,095 shares of common stock.

(11) SIGNIFICANT CUSTOMERS

The Company had oil and natural gas sales to three customers accounting for
22 percent, 14 percent and 13 percent, respectively, of total oil and natural
gas revenues, excluding the effects of hedging activities, for the year ended
December 31, 2004. 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

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

total oil and natural gas revenues, excluding the effects of hedging activities,
for the year ended December 31, 2002.

(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 the change in fair value from hedging
transactions that are determined to be ineffective are recorded in other
revenue, whereas gains and losses from the settlement of hedging contracts are
recorded in oil and gas 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.

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, 2004:

Subsequent to December 31, 2004, we entered into the following contracts:

For the years ended December 31, 2004, 2003 and 2002, settlements of
hedging contracts reduced oil and gas revenues by $15.2, $11.5 and $5.0 million,
respectively. The Company has not discontinued hedge accounting treatment in the
years presented, and therefore, has not reclassified any gains or losses into
earnings as a result.

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table reconciles the change in accumulated other
comprehensive income for the years ended December 31, 2004 and 2003:

Based upon current prices, the Company expects to transfer approximately
$1.7 million of pretax net deferred losses in accumulated other comprehensive
income as of December 31, 2004 to earnings during 2005 when the forecasted
transactions actually occur.

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(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, 2004 and 2003. 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.

(14) INCOME TAXES

Components of income tax expense (benefit) for the years ended December 31,
2004, 2003 and 2002 are as follows:

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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,
2004 and 2003 are presented below:

At December 31, 2004, the Company had net operating loss carryforwards of
approximately $44.3 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 at December 31, 2004 and 2003.
The 2004 tax provision includes the use of $9.0 million of net operating loss
carryforwards.

(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, restricted share units 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

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 vested and were 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 per share in April 2003.
The grant date fair value of the restricted stock and options was $17.00.

The Company issued restricted stock and restricted share unit awards to
employees and officers in the amount of 333,759 in 2004, 131,754 in 2003 and
92,990 in 2002. The restrictions on this stock generally lapse on the first,
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, 2004, 2003 and 2002 was approximately $15.23, $10.12 and $8.19,
respectively.

The Company has recognized non-cash compensation expense of $1.8 million,
$0.8 million and $0.5 million in 2004, 2003 and 2002, respectively, related to
the restricted share and stock option grants. At December 31, 2004, there was
$3.4 million of deferred stock based compensation expense related to the
restricted share awards, which will be recognized over the remaining vesting
periods.

In 2004 and 2003, respectively, 137,000 and 141,500 performance shares were
awarded of which 54,167 and 13,333 were forfeited in 2004 and 2003,
respectively, leaving 211,000 performance shares outstanding at December 31,
2004. 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 $1.3 million and $0.5 million
related to these awards in 2004 and 2003, respectively.

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.

60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A summary of stock options granted under the incentive plans for the years
ended December 31, 2004, 2003 and 2002 are as follows:

A summary of information regarding stock options outstanding at December
31, 2004 is as follows:

The Company also has a 401(k) Plan that covers all employees. The 401(k)
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. By a subsequent amendment in November 2004, the
Company match was increased, effective January 1, 2005, to 100% of each
individual participant's contribution not to exceed 6% 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 401(k) Plan of
13,210, 15,343 and 9,206 shares of common stock in 2004, 2003 and 2002 valued at
approximately $207,000, $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 2006.

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Future minimum commitments as of December 31, 2004 under these operating
obligations are as follows (in thousands):

2005........................................................ $ 6,441
2006........................................................ 3,584
2007........................................................ 1,983
2008........................................................ 1,972
2009........................................................ 1,459
Thereafter.................................................. 2,015
-------
$17,454
=======

Expense relating to operating obligations for the years ended December 31,
2004, 2003 and 2002 was $6.3 million, $3.7 million and $3.3 million,
respectively.

Commencing January 1, 2002, the Company was required to make monthly
deposits of $250,000 into a trust for future abandonment costs at East Bay. The
Company was not entitled to access the trust fund in order to draw funds for
abandonment purposes prior to December 31, 2003. Monthly deposits were not
required to be made for fiscal year 2004 and are to resume January 1, 2005.
Beginning December 31, 2003 the minimum balance in the trust must be maintained
at $6.0 million (with a maximum balance not to exceed $15.0 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

Pursuant to the Company's stockholder agreement with Evercore, the Company
paid an affiliate of Evercore a monitoring fee of $250,000 for the years 2003
and 2002. The requirement to pay this fee ceased in November 2003 when
Evercore's beneficial ownership of the Company's stock became less than 10% and
the stockholder agreement terminated by its terms. 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.

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(18) INTERIM FINANCIAL INFORMATION (UNAUDITED)

The following is a summary of consolidated unaudited interim financial
information for the years ended December 31, 2004 and 2003:

(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.

63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2004

64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2004

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2004

65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(20) NEW ACCOUNTING PRONOUNCEMENTS

In November 2004, the FASB issued Statement of Financial Accounting
Standards No. 151 "Inventory Costs, an amendment of ARB No. 43, Chapter 4"
("Statement 151"). The amendments made by Statement 151 clarify that abnormal
amounts of idle facility expense, freight, handling costs, and wasted materials
(spoilage) should be recognized as current-period charges and require the
allocation of fixed production overheads to inventory based on the normal
capacity of the production facilities. The guidance is effective for inventory
costs incurred during fiscal years beginning after June 15, 2005. Earlier
application is permitted for inventory costs incurred during fiscal years
beginning after November 23, 2004. The Company's assessment of the provisions of
Statement 151 is that it is not expected to have an impact on the financial
position, results of operations or cash flows of the Company.

In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 152 "Accounting for Real Estate Time-Sharing Transactions -- An
Amendment to FASB Statements No. 66 and 67" ("Statement No. 152"). Statement 152
amends FASB Statement No. 66, "Accounting for Sales of Real Estate," to
reference the financial accounting and reporting guidance for real estate
time-sharing transactions that is provided in AICPA Statement of Position (SOP)
04-2, "Accounting for Real Estate Time-Sharing Transactions." Statement 152 also
amends FASB Statement No. 67, "Accounting for Costs and Initial Rental
Operations of Real Estate Projects," to state that the guidance for (a)
incidental operations and (b) costs incurred to sell real estate projects does
not apply to real estate time-sharing transactions. The accounting for those
operations and costs is subject to the guidance in SOP 04-2. Statement 152 is
effective for financial statements for fiscal years beginning after June 15,
2005. The Company's assessment of the provisions of Statement 152 is that it is
not expected to have an impact on the financial position, results of operations
or cash flows of the Company.

In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 153 "Exchanges of Non-monetary assets -- an amendment of APB
Opinion No. 29" ("Statement 153"). Statement 153 amends Accounting Principles
Board (APB) Opinion 29 to eliminate the exception for nonmonetary exchanges of
similar productive assets and replaces it with a general exception for exchanges
of nonmonetary assets that do not have commercial substance. A nonmonetary
exchange has commercial substance if the future cash flows of the entity are
expected to change significantly as a result of the exchange. Statement 153 does
not apply to a pooling of assets in a joint undertaking intended to fund,
develop, or produce oil or natural gas from a particular property or group of
properties. The provisions of Statement 153 shall be effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early
adoption is permitted and the provisions of Statement 153 should be applied
prospectively. The Company's assessment of the provisions of Statement 153 is
that it is not expected to have an impact on the financial position, results of
operations or cash flows of the Company.

In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 123-Revised 2004, "Share-Based Payment," ("Statement 123R"). This
is a revision of Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation", and supersedes APB No. 25,
"Accounting for Stock Issued to Employees." The Company currently accounts for
stock-based compensation under the provisions of APB No. 25. Under Statement
123R, the Company will be required to measure the cost of employee services
received in exchange for stock based on the grant-date fair value (with limited
exceptions). That cost will be recognized as expense over the period during
which an employee is required to provide service in exchange for the award
(usually the vesting period). The fair value will be estimated using an
option-pricing model. Excess tax benefits, as defined in Statement 123R, will be
recognized as an addition to paid-in capital. This is effective as of the
beginning of the first interim or annual reporting period that begins after June
15, 2005. The Company is currently in the process of evaluating the impact of
Statement 123R on its financial statements, including different option-pricing
models. Note (2)(j) illustrates the current effect on net income and earnings
per share if the Company had applied the fair value recognition provisions of
Statement 123.

66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(21) SUBSEQUENT EVENTS -- (UNAUDITED)

On January 20, 2005, the Company closed an acquisition of properties and
reserves in south Louisiana for $146.0 million in cash, after adjustments for
the exercise of preferential rights by third parties and preliminary closing
adjustments. The acquisition is composed of nine fields, four of which were
producing at the time of the closing through 14 wells, with estimated proved
reserves of 51.2 Bcfe. Also included were interests in 22 exploratory prospects.
The transaction expands the Company's exploration opportunities in its expanded
focus area and further reduces the concentration of its reserves and production.
Upon the signing of the purchase agreement, the Company paid a $5.0 million
deposit in 2004 toward the purchase price which is recorded as other assets in
the consolidated balance sheet, and concurrent with the closing, the borrowing
base under the Company's bank credit facility was increased to provide for a
$150 million borrowing base of which $60 million was drawn to fund the
acquisition. In connection with the acquisition, the Company has also entered
into a two-year agreement with the seller of the properties that defines an area
of mutual interest ("AMI") encompassing over one million acres. The Company
intends to continue to explore and develop oil and gas reserves in the AMI over
the next two years jointly with the seller. The proved reserves, prospects and
the AMI are in the southern portions of Terrebone, Lafourche and Jefferson
Parishes in Louisiana. The Company does not have enough information at this time
to prepare the purchase price allocation, however, it believes that the entire
purchase price will be allocated to oil and natural gas assets and asset
retirement obligation. The results of operations of the acquired properties will
be included in the Company's 2005 consolidated statement of operations following
the closing date of January 20, 2005.

On March 8, 2005, the Company closed the acquisition of the remaining 50%
gross working interest in South Timbalier 26, above approximately 13,000 feet
subsea that it did not already own, from Apache Corporation for approximately
$21.0 million after preliminary closing adjustments from the effective date of
December 1, 2004. As a result of the acquisition, the Company now owns a 100%
gross working interest in this field. The acquisition expands the Company's
interest in its core Greater Bay Marchand area and gives the Company additional
flexibility in undertaking the future development of the South Timbalier 26
field. The Company does not have enough information at this time to prepare the
purchase price allocation, however, it believes that the entire purchase price
will be allocated to oil and natural gas assets and asset retirement obligation.
The results of operations of the additional interest acquired will be included
in the Company's 2005 consolidated statement of operations for periods following
the closing of the acquisition.

On February 28, 2005, the Company gave notice of the redemption of all of
the Series D Preferred Stock issued in connection with the HHOC acquisition
(notes 6 and 10) that remain outstanding on the redemption date of March 21,
2005. The redemption price is $100 per share plus accrued and unpaid dividends
to the redemption date, which are estimated to be $1.75 per share. Holders of
record have the right to convert their shares into shares of common stock
through the close of business on March 18, 2005. As of February 28, 2005,
115,100.11 shares of Series D Preferred Stock remained outstanding convertible
into a total of 1,347,776 shares of common stock.

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

Our December 31, 2004, 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. 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
67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

estimates presented in connection with financial statement disclosures. Proved
reserves are estimated quantities of natural gas, crude oil and condensate that
geological and engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved-developed reserves are proved reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods.

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

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

68

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, 2004, 2003 and 2002
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.

69

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, 2004, 2003 and 2002 is as follows:

The December 31, 2004 computation was based on period-end prices of $6.23
per Mcf for natural gas and $41.84 per barrel for crude oil. 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. Spot prices as of February 25, 2005
were $6.33 per Mmbtu for natural gas and $48.25 per barrel for crude oil before
adjustment for lease quality, transportation fees and price differentials.

70

SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

71

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE 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. There was no change in our internal control over financial
reporting during the fiscal quarter ended December 31, 2004 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.

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. See Management's Report on Internal Control Over Financial Reporting and
the Report of Independent Registered Public Accounting Firm -- Internal Control
Over Financial Reporting, which are included herein.

ITEM 9B. OTHER INFORMATION

None.

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
12, 2005, 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 which is available on our website at
www.eplweb.com. A copy is also available by writing to the Secretary of the
Company at 210 St. Charles

72

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
12, 2005, 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 12, 2005, 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, 2004, with
respect to compensation plans under which our equity securities are authorized
for issuance.

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

(1) Comprised of 1,247,964 shares subject to issuance upon the exercise of
options, 211,000 shares issued as performance shares and 248,530 shares to
be issued upon the lapsing of restrictions associated with restricted share
units

(2) Restricted share units and performance shares do not have an exercise price;
therefore this only reflects the option exercise price.

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
12, 2005, 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
12, 2005, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

73

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents to be filed as part of this Report:

1. Financial Statements:

The following financial statements are included in this Report on Form
10-K:

Management's Report on Internal Control Over Financial Reporting

Report of Independent Registered Public Accounting Firm -- Internal
Control Over Financial Reporting

Report of Independent Registered Public Accounting
Firm -- Consolidated Financial Statements

Consolidated Balance Sheets as of December 31, 2004 and 2003

Consolidated Statements of Operations for the years ended December
31, 2004, 2003 and 2002

Consolidated Statements of Changes in Stockholders' Equity for the
years ended December 31, 2004, 2003 and 2002

Consolidated Statements of Cash Flows for the years ended December
31, 2004, 2003 and 2002

Notes to the Consolidated Financial Statements

2. Financial Statement Schedules:

Schedule II -- Valuation and Qualifying Accounts.

(b) Exhibits

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

* Filed herewith

75

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.