ENERGY PARTNERS LTD - 10-Q Quarterly Report

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

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FORM 10-Q

(Mark One)

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

For The Quarterly Period Ended June 30, 2002

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

Commission file number 001-16179
--------------------------------

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

Delaware 72-1409562
(State or other jurisdiction (I.R.S. employer
of incorporation or organization) identification number)

201 St. Charles Avenue, Suite 3400
New Orleans, Louisiana 70170
(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area code: (504) 569-1875

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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 [ ]

As of August 9, 2002, there were 27,513,094 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.

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TABLE OF CONTENTS

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ITEM 1. FINANCIAL STATEMENTS

ENERGY PARTNERS, LTD.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

See accompanying notes to consolidated financial statements.

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ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)

See accompanying notes to consolidated financial statements.

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ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.

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ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2001 AND 2000
(UNAUDITED)

(1) BASIS OF PRESENTATION

Certain information and footnote disclosures normally in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to rules and regulations of the
Securities and Exchange Commission; however, management believes the disclosures
which are made are adequate to make the information presented not misleading.
These financial statements and footnotes should be read in conjunction with the
financial statements and notes thereto included in the Company's Annual Report
on Form 10-K for the year ended December 31, 2001 and Management's Discussion
and Analysis of Financial Condition and Results of Operations.

The financial information as of June 30, 2002 and for the three and six
month periods ended June 30, 2002 and 2001, has not been audited. However, in
the opinion of management, all adjustments (which include only normal recurring
adjustments) necessary to present fairly the results of operations for the
periods presented have been included therein. The results of operations for the
first six months of the year are not necessarily indicative of the results of
operations, which might be expected for the entire year.

(2) BUSINESS COMBINATION

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

The acquisition was completed for consideration consisting of $38.4 million
liquidation preference of newly authorized and issued Series D Exchangeable
Convertible Preferred Stock (the "Series D Preferred Stock"), with a fair value
of $34.7 million discounted to effect the increasing dividend rate, $38.4
million of 11% Senior Subordinated Notes, due 2009 (the "Notes"), 574,931 shares
of common stock with a fair value of $3.3 million determined based on the
average market price of the Company's common stock over the period of two days
before and after the terms of the acquisition were agreed to and announced, $9.0
million of cash including $3.9 million of accrued interest and prepayment fees
paid to former debt holders and warrants to purchase four million shares of the
Company's common stock. Of the warrants, one million have a strike price of
$9.00 and three million have a strike price of $11.00 per share. The warrants
had a fair value of $2.9 million based on a third party valuation. In addition,
the Company incurred approximately $3.6 million of expenses in connection with
the acquisition and assumed HHOC's working capital deficit.

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ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

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

The following table summarizes the fair value of the assets acquired and
liabilities assumed at the date of acquisition. The purchase price allocation is
still subject to refinement primarily based on the actual merger costs incurred.

Concurrent with the closing of the acquisition, the Company amended its
revolving line of credit with a group of banks (the "bank facility"). The new
terms provide for a $100 million borrowing base that is subject to
redetermination based on the proved reserves of the oil and gas properties that
serve as collateral for the bank facility as set out in the reserve report
delivered to the bank each April 1 and October 1. The bank facility as amended
is available through March 30, 2005 with interest permitted at both prime rate
based borrowings and London interbank offered rate ("LIBOR") based borrowings
plus a floating spread. The spread will float up or down based on the Company's
utilization of the bank facility. The spread can range from 1.50% to 2.25% above
LIBOR and 0% to 0.75% above prime. Indebtedness under the bank facility is
secured by substantially all of the assets of the Company.

The following unaudited pro forma information for the three and six month
periods ended June 30, 2001 presents a summary of the consolidated results of
operations as if the acquisition occurred on January 1, 2001 with pro forma
adjustments to give effect to depreciation, depletion and amortization, interest
expense and related income tax effects (in thousands, except per share amounts):

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ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

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

Following the completion of the acquisition, management of the Company
assessed the technical and administrative needs of the combined organization. As
a result, 14 redundant positions were eliminated including finance,
administrative, geophysical and engineering positions in New Orleans and
Houston. All terminated employees were informed of their termination date and
severance benefits prior to March 31, 2002. Total severance costs under the plan
were $1.2 million, all of which was included in accrued expenses in the March
31, 2002 consolidated balance sheet had been paid as of June 30, 2002 without
any changes from the amount expensed in the first quarter to the actual amount
ultimately paid.

(3) 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 reflects the potential dilution that
could occur if the Company's dilutive stock options and warrants were exercised
(calculated using the treasury stock method) and if the Company's convertible
preferred stock were converted to common stock.

The following tables reconcile the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
the three and six month periods ended June 30, 2001. The diluted loss per share
calculation for the three and six months ended June 30, 2002 produces results
that are anti-dilutive, therefore, the diluted loss per share amounts as
reported for that period in the accompanying consolidated statements of
operations are the same as the basic loss per share amounts (in thousands,
except per share amounts).

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ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

(4) HEDGING ACTIVITIES

The Company enters into hedging transactions with major financial
institutions to reduce exposure to fluctuations in the price of oil and natural
gas. Crude oil hedges are settled based on the average of the reported
settlement prices for West Texas Intermediate crude on the New York Mercantile
Exchange ("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 uses financially-settled crude oil and
natural gas swaps and zero-cost collars to hedge price fluctuations. The
Company's current derivative instruments qualify as cash-flow hedges. 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 and
measured at fair value. The accounting for changes in fair value depends on the
intended use of the derivative and the resulting designation, which is
established at the inception of the derivative. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the statement of operations. For derivative
instruments designated as cash-flow hedges, changes in fair value, to the extent
the hedge is effective, will be recognized in other comprehensive income (a
component of stockholders' equity) until settled, when the resulting gains and
losses will be recorded in earnings. Hedge ineffectiveness is measured at least
quarterly based on the relative changes in fair value between the derivative
contract and the hedged item over time. Any change in fair value resulting from
ineffectiveness, will be charged currently to earnings.

As of June 30, 2002, the Company had contracts maturing monthly through
December 2002 related to the net sale of 368,000 barrels of crude oil (2,000
barrels per day) at an average price of 24.20 per barrel.

As of June 30, 2002, the Company had a natural gas swap that covered
6,450,000 Mmbtu (30,000 Mmbtu per day) at $2.95 per Mmbtu maturing monthly
through January 2003. The Company also has financially-settled natural gas
collar positions maturing monthly beginning February 2003 through January 2004
related to the net sale of 3,650,000 Mmbtu (10,000 Mmbtu per day) of natural gas
with a floor of $3.50 per Mmbtu and a cap of $5.40 per Mmbtu.

Hedging activities reduced natural gas and crude oil revenues by $1.4
million and $0.1 million in the three and six month periods ended June 30, 2002
and reduced natural gas and crude oil revenues by $2.1 million and $5.2 million
in the three and six month periods ended June 30, 2001.

During the first six months of 2002, losses of $0.1 million, net of tax,
were transferred from accumulated other comprehensive income (loss) and the fair
value of outstanding derivative instruments decreased by $5.5 million ($3.5
million net of tax) to a liability of $3.8 million ($2.4 million net of tax)
resulting in an ending balance of $2.4 million related to hedging activities in
accumulated other comprehensive income (loss) at June 30, 2002. Based upon
current prices, the Company expects to transfer approximately $3.5 million of
net deferred losses in accumulated other comprehensive income (loss) as of June
30, 2002 to earnings during the remainder of 2002 when the forecasted
transactions actually occur.

(5) CONTINGENCIES

In the ordinary course of business, the Company is a defendant in various
legal proceedings. The Company does not expect its exposure in these
proceedings, individually or in the aggregate, to have a material adverse effect
on the financial position, results of operations or liquidity of the Company.

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ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)

(6) ACCOUNTING PRONOUNCEMENTS

In 2001, the Financial Accounting Standards Board ("FASB") issued
Statement 143, Accounting for Asset Retirement Obligations ("Statement 143").
Statement 143 requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset
and is effective for fiscal years beginning after June 15, 2002. The Company
will adopt Statement 143 effective January 1, 2003, using the cumulative effect
approach to recognize transition amounts for asset retirement obligations, asset
retirement costs and accumulated depreciation. The Company currently records
estimated costs of dismantlement, removal, site restoration and similar
activities as part of its depreciation, depletion and amortization for oil and
gas properties and records a separate liability for such amounts in other
liabilities. The Company has not yet completed its assessment of the impact of
Statement 143 on its financial condition and results of operations, however, it
expects that adoption of the statement will result in increases in the
capitalized costs of oil and gas properties and in the recognition of additional
liabilities related to asset retirement obligations.

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

(7) RECLASSIFICATIONS

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

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ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

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

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. Our
annual report on Form 10-K includes a discussion of our critical accounting
policies, which have not significantly changed.

On January 15, 2002, we acquired HHOC for consideration of $91.9 million and
the assumption of HHOC's working capital deficit. The acquisition moved our
operations to a more balanced natural gas and oil production profile and reduced
our production exposure to any particular field. Through the acquisition we
added approximately 59.0 Bcfe of proved reserves, 97% of which are natural gas.
The acquisition included 10 producing properties and 12 offshore exploratory
blocks. As the closing did not occur until January 2002, the impact of the
acquisition is not reflected in our financial statements for fiscal 2001.

Financing related to the HHOC acquisition increased our debt level. At the
closing of the acquisition, we issued the Notes for $38.4 million and borrowed
$9.0 million cash paid from our bank facility. Additional bank borrowings have
been for operational needs and to reduce the HHOC working capital deficit we
assumed in the acquisition. As of June 30, 2002, we had $60.0 million
outstanding under our bank facility. We also issued Series D Preferred Stock
with a fair value at the issue date of $34.7 million ($38.4 million face amount)
with an effective dividend rate of 10%.

We have included the results of operations from the HHOC acquisition with
ours from the closing date of January 15, 2002. For the foregoing reason, the
acquisition will affect the comparability of our historical results of
operations with results of operations in the current period.

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

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ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)

RESULTS OF OPERATIONS

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

(1) Net of the effect of hedging transactions

PRODUCTION

CRUDE OIL AND CONDENSATE. Our net oil production for the second quarter of
2002 decreased to 9,067 Bbls per day from 10,444 Bbls per day in the second
quarter of 2001. Our net oil production for the first six months of 2002
decreased to 8,972 Bbls per day from 10,579 Bbls per day in the same period
2001. The decrease is the result of fewer workovers/recompletions on oil wells
in the current year combined with natural reservoir declines.

NATURAL GAS. Our net natural gas production for the second quarter of 2002
increased to 56,550 Mcf per day from 34,718 Mcf per day in the second quarter of
2001. Our net natural gas production for the first six months of 2002 increased
to 54,956 Mcf per day from 34,098 Mcf per day in the same period of 2001. The
increase for the quarter and six months was the result of natural gas volumes
added in the acquisition of HHOC and was partially offset by natural reservoir
declines from other producing wells.

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ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)

REALIZED PRICES

CRUDE OIL AND CONDENSATE. Our average realized oil price in the second
quarter of 2002 was $23.90 per Bbl, an increase from an average realized price
of $23.67 per Bbl in the second quarter of 2001. Hedging activities reduced oil
price realizations by $0.36 per Bbl from the $24.26 per Bbl that would have
otherwise been received in the second quarter of 2002. In the second quarter of
2001, hedging activities reduced oil price realizations by $2.15 per Bbl or 8%
from the $25.82 per Bbl that would have otherwise been received.

Our average realized oil price in the first half of 2002 was $22.12 per
Bbl, a decrease of 8% from an average realized price of $23.98 per Bbl in the
first half of 2001. Hedging activities reduced oil price realizations by $0.18
per Bbl from the $22.30 per Bbl that would have otherwise been received in the
first half of 2002. In the first half of 2001, hedging activities reduced oil
price realizations by $2.67 per Bbl or 10% from the $26.65 per Bbl that would
have otherwise been received.

NATURAL GAS. Our average realized natural gas price in the second quarter
of 2002 was $3.30 per Mcf, a decrease of 29% from an average realized price of
$4.68 per Mcf in the second quarter of 2001. Hedging activities reduced natural
gas price realizations by $0.22 per Mcf or 6% from the $3.52 per Mcf that would
have otherwise been received in the second quarter of 2002. As a result of our
natural gas collar positions, hedging activities did not impact realized prices
in the second quarter of 2001.

Our average realized natural gas price in the first half of 2002 was $3.04
per Mcf, a decrease of 50% over an average realized price of $6.08 per Mcf in
the first half of 2001. In the first half of 2002, hedging activities increased
natural gas price realizations by $0.02 per Mcf from the $3.02 per Mcf that
would have otherwise been received. In the first half of 2001, hedging
activities reduced natural gas price realizations by $0.01 per Mcf from the
$6.09 per Mcf that would have otherwise been received.

NET INCOME AND REVENUES

Our oil and natural gas revenues decreased to $36.7 million in the second
quarter of 2002 from $37.3 million in the second quarter of 2001. Production
volumes increased 14% on a barrel of oil equivalent basis, however, the increase
due to higher natural gas production was offset by decreased gas prices,
resulting in relatively flat revenues.

Our oil and natural gas revenues decreased to $66.2 million in the first
half of 2002 from $83.5 million in the first half of 2001. While production
volumes increased 11%, the increase was more than offset by a sharp decrease in
natural gas prices, resulting in lower revenues.

We recognized net income of $0.4 million in the second quarter of 2002
compared to net income of $3.4 million in the second quarter of 2001. We
recognized a net loss of $5.4 million in the first half of 2002 compared to net
income of $17.5 million in the first half of 2001. The decrease in net income
was primarily due to the decrease in oil and natural gas revenues previously
discussed, combined with higher depletion, depreciation and amortization expense
primarily as a result of the HHOC acquisition. In addition, there were two
non-recurring items that had an impact on our net income or loss in the first
half of 2002 and 2001:

o We recorded business interruption income of $3.5 million ($2.2 million on
an after tax basis or $0.08 per diluted share) in the first quarter of 2001
as a result of the rupture of a high-pressure natural gas transfer line at
our East Bay field. The rupture occurred in November 2000 and the transfer
line was restored to service in February 2001.

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ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)

o 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 ($0.8 million on an
after tax basis or $0.03 per diluted share).

OPERATING EXPENSES

Operating expenses during the three and six month periods ended June 30, 2002
and 2001 were impacted by the following:

o Lease operating expense decreased to $8.5 million in the second quarter of
2002 from $9.8 million in the second quarter of 2001. The decrease is
attributable to the concerted effort to reduce operating costs at our East
Bay field and the increase in natural gas production as a percentage of
total production. Natural gas has a lower per unit lease operating cost
than oil. In addition in 2001 we incurred $0.7 million on 8 workovers and
had repair costs as a result of Tropical Storm Allison.

Lease operating expense decreased to $17.3 million in the first half of
2002 from $18.8 million in the first half of 2001. The decrease is due to
the reasons discussed above.

o Taxes, other than on earnings decreased to $1.6 million in the second
quarter of 2002 from $2.0 million in the second quarter of 2001. Taxes,
other than on earnings decreased to $3.2 million in the first half of 2002
from $3.8 million in the first half of 2001. Both reductions were due to
the decrease in the production volumes and prices received for our oil
production on state leases subject to Louisiana severance taxes.

o Depreciation, depletion and amortization increased to $17.9 million in the
second quarter of 2002 from $11.6 million in the second quarter of 2001.
Depreciation, depletion and amortization increased to $34.3 million in the
first half of 2002 from $22.3 million in the first half of 2001. The
increases were due to the increased depreciable asset base resulting from
the acquisition of HHOC and drilling activities subsequent to June 30,
2001, increased production volumes, amortization of unproved leases awarded
from the March lease sale and downward reserve revisions due to prices at
December 31, 2001.

o Other general and administrative expenses increased to $5.0 million in the
second quarter of 2002 from $4.9 million in the second quarter of 2001. The
increase was due to increased insurance costs ($0.2 million), and increased
office costs ($0.3 million) resulting from the combination of HHOC's
operations with ours, offset by decreased consultant fees.

Other general and administrative expenses increased to $11.3 million in the
first half of 2002 from $8.8 million in the first half of 2001. The
increase was primarily due to additional personnel costs ($0.3 million),
increased insurance costs ($1.0 million), increased office costs ($0.6
million) and other costs associated with the combination of HHOC's
operations with ours.

o Non-cash stock-based compensation expense of $0.1 million was recognized in
the second quarter of 2002 compared to $0.3 million in the second quarter
of 2001. Non-cash stock-based compensation expense of $0.3 million was
recognized in the first half of 2002 compared to $1.1 million recognized in
the first half of 2001. The expense relates to restricted stock and stock
option grants made in April and October 2000 and January 2002.

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ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)

OTHER INCOME AND EXPENSE

INTEREST. Interest expense increased to $1.8 million in the second quarter
of 2002 from $0.4 million in the second quarter of 2001. Interest expense also
increased for the year to date period to $3.4 million in 2002 from $0.9 million
in 2001. The increases for both periods was a result of increased borrowings
under our bank facility and the issuance of the Notes on January 15, 2002.

LIQUIDITY AND CAPITAL RESOURCES

We intend to use cash flows from operations and our revolving line of
credit to fund our future development, exploration and acquisition activities.
Our acquisition in 2002 of HHOC significantly impacted our cash flows from
operations. Our future cash flow from operations will depend on our ability to
maintain and increase production through our development and exploration
drilling program, as well as the prices of oil and natural gas.

Our bank facility, as amended on January 15, 2002, consists of a revolving
line of credit with a group of banks available through March 30, 2005. The bank
facility currently has a borrowing base of $100 million that is subject to
redetermination based on the proved reserves of the oil and gas properties that
serve as collateral for the bank facility as set out in the reserve report
delivered to the bank each April 1 and October 1. The bank facility permits both
prime rate based borrowings and LIBOR based borrowings plus a floating spread.
The spread will float up or down based on our utilization of the bank facility.
The spread can range from 1.50% to 2.25% above LIBOR and 0% to 0.75% above
prime. The borrowing base under the bank facility is secured by substantially
all of our assets including those of HHOC acquired in January 2002. The bank
facility contains customary events of default and requires that we satisfy
various financial covenants. At June 30, 2002, we had $60 million outstanding
and $40 million of credit capacity available under the bank facility. Also
included in long-term debt in the consolidated balance sheet is $38.4 of Senior
Subordinated Notes, which are due in January 2009.

Net cash of $21.7 million used in investing activities in the first six
months of 2002 consisted primarily of the $10.7 million of cash paid in
conjunction with the acquisition of HHOC, which is net of $1.9 million in cash
received. The remainder was for lease acquisitions of $1.1 million and oil and
gas property capital and exploration expenditures. Exploration expenditures
incurred are excluded from operating cash flows and included in investing
activities. During the first half of 2002, we completed 3 drilling projects, all
of which were successful and 11 recompletion/workover projects, 9 of which were
successful. During the first half of 2001, we completed 15 drilling projects, 11
of which were successful and 32 recompletion/workover projects, 27 of which were
successful.

Our 2002 capital expenditure budget is focused on moderate risk exploratory
activities on undeveloped leases, combined with exploitation and exploration
activities on our proved properties. We currently expect that up to 10 percent
of our budget will be spent on high risk, high potential exploration activities.
Our capital expenditure plans for 2002 are currently estimated to range between
$60 million and $80 million. Actual levels of capital expenditures may vary
significantly due to many factors, including the integration of projects on the
properties acquired from HHOC in January 2002, 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.

We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active capital expenditure
program. We believe that working capital, cash flows from operations and
borrowings under our credit facility will be sufficient to meet our capital
requirements through the end of 2002. However, additional financing may be
required in the future to fund our growth and capital expenditures.

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ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)

Our annual report on Form 10-K for the year ended December 31, 2001
included a discussion of our contractual obligations inclusive of the Notes
issued in the HHOC acquisition. As a result, the only change to that disclosure
is the increase in borrowings under our bank facility discussed herein.

NEW ACCOUNTING PRONOUNCEMENTS

In 2001, the Financial Accounting Standards Board ("FASB") issued Statement
143, Accounting for Asset Retirement Obligations ("Statement 143"). Statement
143 requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long-lived asset and is effective
for fiscal years beginning after June 15, 2002. We will adopt Statement 143
effective January 1, 2003, using the cumulative effect approach to recognize
transition amounts for asset retirement obligations, asset retirement costs and
accumulated depreciation. We currently record estimated costs of dismantlement,
removal, site restoration and similar activities as part of its depreciation,
depletion and amortization for oil and gas properties and record a separate
liability for such amounts in other liabilities. We have not yet completed our
assessment of the impact of Statement 143 on our financial condition and results
of operations, however, we expect that adoption of the statement will result in
increases in the capitalized costs of oil and gas properties and in the
recognition of additional liabilities related to asset retirement obligations.

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

FORWARD LOOKING INFORMATION

All statements other than statements of historical fact contained in this
Report and other periodic reports filed by us under the Securities Exchange Act
of 1934 and other written or oral statements made by us or on our behalf, are
forward-looking statements. When used herein, the words "anticipates",
"expects", "believes", "goals", "intends", "plans", or "projects" and similar
expressions are intended to identify forward-looking statements. It is important
to note that forward-looking statements are based on a number of assumptions
about future events and are subject to various risks, uncertainties and other
factors that may cause our actual results to differ materially from the views,
beliefs and estimates expressed or implied in such forward-looking statements.
We refer you specifically to the section "Additional Factors Affecting Business"
in Items 1 and 2 of our Annual Report on Form 10-K for the year ended December
31, 2001. 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 document are expressly qualified in their
entirety by the cautionary statements in this paragraph.

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ENERGY PARTNERS, LTD.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

We are exposed to changes in interest rates. Changes in interest rates
affect the interest earned on our cash and cash equivalents and the interest
rate paid on borrowings under the credit agreements. Currently, we do not use
interest rate derivative instruments to manage exposure to interest rate
changes. At June 30, 2002, $60 million of our long-term debt had variable
interest rates and $38.4 million had a fixed rate of 11%.

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 credit agreement 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. Our hedging program uses
financially-settled crude oil and natural gas swaps and zero-cost collars
benchmarked to the NYMEX West Texas Intermediate crude oil contracts and Henry
Hub natural gas contracts. We do not use them for speculative purposes.

As of June 30, 2002, we had crude oil contracts maturing monthly through
December 31, 2002 related to the sale of 368,000 barrels of crude oil (2,000
barrels per day) at an average price of $24.20 per barrel. As of June 30, 2002,
we also had a natural gas swap covering 6,450,000 Mmbtu (30,000 Mmbtu per day)
at $2.95 per Mmbtu maturing monthly through January 2003. In addition, in May
2002, we entered into financially-settled natural gas collar positions maturing
monthly beginning February 2003 through January 2004 related to the net sale of
3,650,000 Mmbtu (10,000 Mmbtu per day) of natural gas with a floor of $3.50 per
Mmbtu and a cap of $5.40 per Mmbtu.

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.

Our hedged volume as of June 30, 2002, approximated 23% of our estimated
production from proved reserves for the balance of the contract terms.

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 June 30, 2002, the potential change
in the fair value of commodity derivative instruments assuming a 10% adverse
movement in the underlying commodity price is a $4.1 million increase in the
deferred liability.

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

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PART II. OTHER INFORMATION

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

a) At the Annual Meeting of Stockholders of the Company held on May 9, 2002,
the stockholders elected certain directors to serve until the 2003 Annual
Meeting of Stockholders, approved the Company's Amended and Restated 2000
Long Term Stock Incentive Plan and ratified the appointment of KPMG LLP as
independent certified public accountants to audit the Company's
consolidated financial statements for the year ended December 31, 2002.

The voting tabulation is as follows:

b) At the Special Meeting of Stockholders of the Company held on June 25,
2002, the only matter voted upon was the acquisition of Hall-Houston Oil
Company and related transactions.

The voting tabulation is as follows:

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

10.1 First Amendment to Second Amended and Restated Revolving Credit
Agreement dated January 15, 2002 by and among Energy Partners,
Ltd. and Hall-Houston Oil Company, the undersigned banks and
financial institutions that are parties to the Credit Agreement
and Bank One, N.A, dated as of June 27, 2002.

(b) Reports on Form 8-K:

None

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SIGNATURE

Pursuant to the requirements of the Securities Exchange 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.

Date: August 13, 2002 By: /s/ SUZANNE V. BAER
------------------------------------
Suzanne V. Baer
Executive Vice President and
Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)

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CERTIFICATION
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Chapter 63, Title 18 U.S.C. Section 1350(a) and (b))

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the
undersigned hereby certifies in his capacity as an officer of Energy Partners,
Ltd. (the "Company") that the Quarterly Report of the Company on Form 10-Q for
the period ended June 30, 2002 fully complies with the requirements of Section
13(a) of the Securities Exchange Act of 1934 and that the information contained
in such Report fairly presents, in all material respects, the financial
condition and the results of operations of the Company at the end of and for the
periods covered by such Report.

/s/ Richard A. Bachmann
----------------------------
Dated: August 13, 2002 Richard A. Bachmann
Chairman, President and
Chief Executive Officer

/s/ Suzanne V, Baer
----------------------------
Dated: August 13, 2002 Suzanne V. Baer
Executive Vice President
and Chief Financial Officer

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EXHIBIT INDEX