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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
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 (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 November 29, 2000, there were 26,271,297 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
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TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
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<S> <C>
PART I FINANCIAL INFORMATION
Item 1. Financial Statements:
Consolidated Balance Sheets as of September 30, 2000 and
December 31, 1999............................................................................3
Consolidated Statements of Operations for the three months ended
September 30, 2000 and 1999 and for the nine months ended
September 30, 2000 and 1999..................................................................4
Consolidated Statements of Cash Flows for the nine months ended
September 30, 2000 and 1999..................................................................5
Notes to Consolidated Financial Statements .......................................................6
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................................................12
Item 3. Quantitative and Qualitative Disclosures about Market Risk......................................19
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K................................................................20
</TABLE>
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ITEM 1. FINANCIAL STATEMENTS
ENERGY PARTNERS, LTD.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30,
2000 December 31,
(unaudited) 1999
------------- -------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 12,139,585 $ 22,282,376
Trade accounts receivable 19,495,975 7,970,738
Prepaid expenses 1,199,014 300,698
------------- -------------
Total current assets 32,834,574 30,553,812
Property and equipment, at cost under the successful efforts
method of accounting for oil and gas properties 166,476,348 42,241,227
Less accumulated depreciation, depletion and amortization (17,366,892) (5,627,323)
------------- -------------
Net property and equipment 149,109,456 36,613,904
Other assets 843,166 --
Deferred income taxes -- 1,545,049
Deferred financing costs - net of accumulated amortization
of $656,510 in 2000 and $108,130 in 1999 3,082,899 563,093
------------- -------------
Total assets $ 185,870,095 $ 69,275,858
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 8,392,438 $ 4,215,030
Accrued expenses 25,514,440 1,793,339
Current maturities of long-term debt 24,000,000 --
------------- -------------
Total current liabilities 57,906,878 6,008,369
Long-term debt 50,000,000 10,150,000
Deferred income taxes 5,939,006 --
Other 3,978,146 457,386
------------- -------------
117,824,030 16,615,755
------------- -------------
Redeemable Convertible Preferred Stock, $1 par value,
authorized 1,700,000 shares; issued and outstanding
600,000 shares, aggregate liquidation preference
$ 66,313,519 62,405,411 56,475,276
Stockholders' equity:
Common stock, par value $0.01 per share. Authorized
50,000,000 shares; issued and outstanding:
2000 - 11,858,280 shares; 1999 - 11,768,280 shares 118,583 117,683
Additional paid-in capital 2,016,625 32,377
Retained earnings 3,505,446 (3,965,233)
------------- -------------
Total stockholders' equity 5,640,654 (3,815,173)
------------- -------------
Total liabilities and stockholders' equity $ 185,870,095 $ 69,275,858
============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
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ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------------- ---------------------------------
2000 1999 2000 1999
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Revenues:
Oil and gas $ 30,636,424 $ 2,606,858 $ 60,645,594 $ 5,821,044
Other 97,610 252,723 444,693 818,676
------------ ------------ ------------ ------------
30,734,034 2,859,581 61,090,287 6,639,720
------------ ------------ ------------ ------------
Costs and expenses:
Lease operating 6,431,000 406,346 12,879,823 1,029,047
Production taxes 1,745,438 -- 3,288,778 --
Exploration expenditures 268,753 56,464 1,092,948 56,925
Depreciation, depletion and amortization 7,498,720 1,182,855 15,785,213 3,118,674
General and administrative (exclusive
of stock-based compensation) 3,035,212 641,331 7,364,734 1,739,768
Stock-based compensation 737,960 -- 1,985,148 --
------------ ------------ ------------ ------------
Total costs and expenses 19,717,083 2,286,996 42,396,644 5,944,414
------------ ------------ ------------ ------------
Income from operations 11,016,951 572,585 18,693,643 695,306
Other income (expense):
Interest income 116,645 46,029 444,155 130,763
Interest expense (2,782,747) (966,514) (5,839,607) (2,267,563)
Gain on sale of oil and gas assets -- -- 7,781,448 --
------------ ------------ ------------ ------------
(2,666,102) (920,485) 2,385,996 (2,136,800)
------------ ------------ ------------ ------------
Income (loss) before income taxes 8,350,849 (347,900) 21,079,639 (1,441,494)
Income taxes (3,160,528) 132,323 (7,634,055) 507,284
------------ ------------ ------------ ------------
Net income (loss) $ 5,190,321 $ (215,577) $ 13,445,584 $ (934,210)
------------ ------------ ------------ ------------
Less dividends earned on preferred stock
and accretion of issuance costs (1,742,323) -- (5,974,906) --
------------ ------------ ------------ ------------
Net income (loss) available to
common stockholders $ 3,447,998 $ (215,577) $ 7,470,678 $ (934,210)
============ ============ ============ ============
Basic income (loss) per share $ 0.40 $ (0.01) $ 0.88 $ (0.06)
============ ============ ============ ============
Diluted income (loss) per share $ 0.29 $ (0.01) $ 0.75 $ (0.06)
============ ============ ============ ============
Weighted average common shares used
in computing income (loss) per share:
Basic 8,554,500 15,060,000 8,519,026 15,060,000
Incremental common shares 9,528,321 -- 9,528,321 --
------------ ------------ ------------ ------------
Diluted 18,082,821 15,060,000 18,047,347 15,060,000
============ ============ ============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
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ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------------------------
2000 1999
------------- --------------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) $ 13,445,584 $ (934,210)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization 15,785,213 3,118,674
Gain on sale of oil and gas assets (7,781,448) --
Stock-based compensation 1,985,148 --
Deferred income taxes 7,484,055 (507,284)
Exploration expenditures 1,092,948 56,925
Amortization of deferred financing costs 548,380 43,426
------------- -------------
32,559,880 1,777,531
Changes in operating assets and liabilities:
Trade accounts receivable (11,525,237) 3,758,432
Prepaid expenses (898,316) (94,891)
Other assets (843,166) (2,422)
Accounts payable and accrued expenses 8,211,791 (6,546,701)
Other liabilities 193,855 211,238
------------- -------------
Net cash provided by (used in) operating activities 27,698,807 (896,813)
------------- -------------
Cash flows used in investing activities:
Property acquisitions (119,292,744) --
Exploration and development expenditures (15,895,645) (13,672,467)
Proceeds from sale of oil and gas assets 36,609,740 --
------------- -------------
Net cash used in investing activities (98,578,649) (13,672,467)
------------- -------------
Cash flows from financing activities:
Deferred financing costs (3,112,949) (245,258)
Proceeds from long-term debt 108,000,000 19,650,000
Repayment of long-term debt (44,150,000) (2,500,000)
------------- -------------
Net cash provided by financing activities 60,737,051 16,904,742
------------- -------------
Net increase (decrease) in cash and cash equivalents (10,142,791) 2,335,462
Cash and cash equivalents at beginning of period 22,282,376 652,116
------------- -------------
Cash and cash equivalents at end of period $ 12,139,585 $ 2,987,578
============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
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ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999
(UNAUDITED)
(1) BASIS OF PRESENTATION
The consolidated financial statements include the accounts of Energy Partners,
Ltd. (the Company) and EPL Pipeline L.L.C. (a wholly-owned subsidiary of EPL).
EPL Pipeline L.L.C. was formed on February 3, 2000 to own and operate pipeline
assets acquired from Unocal Corporation (Unocal) on March 31, 2000.
Certain information and footnote disclosures normally in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to rules and regulations of the Securities and
Exchange Commission; however, management believes the disclosures which are made
are adequate to make the information presented not misleading. These financial
statements and footnotes should be read in conjunction with the financial
statements and notes thereto included in the Company's registration statement on
Form S-1 as amended (Registration No. 333-42876), filed with the Securities and
Exchange Commission on November 1, 2000.
The financial information as of September 30, 2000 and for the three and nine
months ended September 30, 2000 and 1999, 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 nine months of the year are not necessarily indicative of the results of
operations which might be expected for the entire year.
(2) INITIAL PUBLIC OFFERING
On November 1, 2000, the Company priced its initial public offering of 5.75
million shares of common stock and commenced trading the following day. After
payment of underwriting discounts and commissions, the Company received net
proceeds of $80.2 million on November 7, 2000. With the proceeds, the Company
retired outstanding debt of $73.9 million and paid approximately $5.1 million to
redeem outstanding Series C Preferred Stock. In connection with the initial
public offering, the Company converted all outstanding preferred shares into
shares of common stock.
Following these transactions, the Company had approximately 26.3 million common
shares outstanding. In addition, a stockholder holds a warrant to purchase
928,050 shares of common stock. The warrant became exercisable upon completion
of the initial public offering and is exercisable at approximately $6.50 per
share or through a cashless exercise, in whole or in part for a period of 60
days after the initial public offering.
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<PAGE> 7
ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
(3) PRO FORMA FINANCIAL INFORMATION
The initial public offering closed on November 7, 2000 and is not reflected in
the accompanying consolidated financial statements at and for the three and nine
months ended September 30, 2000. The following pro forma net income (loss) and
pro forma basic and diluted income (loss) per share for the year ended December
31, 1999 and for the nine months ended September 30, 2000 assumes the completion
of the initial public offering, the conversion of the preferred stock into
9,368,921 shares of common stock, redemption of approximately $4.5 million of
Class C preferred stock, the retirement of all outstanding debt on January 1,
1999, and the release to management shareholders of 2,545,500 of escrow shares
with an expense of approximately $38.0 million on January 1, 1999:
<TABLE>
<CAPTION>
For the Year Ended For the Nine
December 31, Months Ended
1999 September 30, 2000
------------------ ------------------
(in thousands, except per share data)
<S> <C> <C>
Pro forma net income (loss) $(38,348) $ 17,184
Pro forma basic income (loss) per common share $ (1.36) $ 0.68
Pro forma diluted income (loss) per common share $ (1.36) $ 0.67
Pro forma weighted average number of common
Shares outstanding:
Basic 28,197 25,367
Diluted 28,197 25,526
</TABLE>
The pro forma net income (loss) for the year ended December 31, 1999 and nine
months ended September 30, 2000 reflects adjustments of approximately $3.0
million and $5.8 million, respectively, to eliminate interest expense as a
result of the retirement of all outstanding debt.
The pro forma weighted average number of common shares outstanding includes
adjustments for the issuance of common shares in connection with the initial
public offering, the conversion of each share of preferred stock into shares of
common stock, and the release of 2,545,000 shares from escrow.
The pro forma condensed consolidated balance sheet at September 30, 2000 assumes
the completion of the initial public offering on that date, the conversion of
each share of preferred stock into 9,368,921 shares of common stock, the
redemption of approximately $4.5 million of Series C preferred stock and the
retirement of all outstanding debt and is as follows (in thousands, except share
data):
<TABLE>
<CAPTION>
September 30, 2000
------------------
(Pro Forma)
<S> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 12,662
Accounts receivable and other 20,695
---------
Total current assets 33,357
PROPERTY AND EQUIPMENT 166,476
Less - Accumulated depreciation, depletion and amortization (17,367)
---------
Total property and equipment 149,109
Other assets 3,926
---------
Total assets $ 186,392
=========
</TABLE>
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ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
<TABLE>
<CAPTION>
September 30, 2000
------------------
(Pro Forma)
<S> <C>
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities $ 33,907
--------
Total current liabilities 33,907
Other liabilities 9,917
--------
Total liabilities 43,824
STOCKHOLDERS' EQUITY:
Common stock, par value; per share authorized 50,000,000
Shares; issued and outstanding: 2000 - 26,251,854 shares,
1999 - 11,768,280 shares 271
Additional paid-in capital 138,792
Retained earnings 3,505
--------
Total stockholders' equity 142,568
--------
Total liabilities and equity $186,392
========
</TABLE>
(4) ACQUISITIONS AND DISPOSITION
On March 31, 2000, the Company purchased an 80% working interest in South
Timbalier 26 from Unocal for approximately $44.9 million, which included $1.25
million for pipeline assets. Additionally, on March 31, 2000, the Company
purchased an average 96.1% working interest in East Bay Field (East Bay) from
Ocean Energy, Inc. for approximately $72.3 million. The entire purchase price
for both acquisitions was allocated to property and equipment. The terms of the
acquisitions did not contain any contingent consideration, options or future
commitments.
On April 20, 2000, the Company sold a 50% working interest in South Timbalier 26
for approximately $36.6 million, resulting in a gain of approximately $7.8
million. The proceeds from this sale were used to reduce the borrowings under
the reducing revolving line of credit.
The unaudited pro forma results of operations, assuming that such acquisitions
and disposition occurred on January 1 of the respective periods, are as follows
(in thousands, except per share amounts):
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2000 1999 2000 1999
------- ------- ------- -------
(Unaudited)
<S> <C> <C> <C> <C>
Proforma:
Revenue............................... $30,734 $22,847 $87,135 $54,543
Income from operations................ 11,017 12,058 32,250 13,265
Net income............................ 5,190 6,027 21,012 3,784
Basic earnings per common share....... $0.40 $ 0.40 $ 1.77 $ 0.25
Diluted earnings per common share..... $0.29 $ 0.40 $ 1.16 $ 0.25
</TABLE>
The proforma financial information does not purport to be indicative of the
results of operations that would have occurred had the acquisitions and
disposition taken place at the beginning of the periods presented or future
results of operations.
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<PAGE> 9
ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
(5) LONG-TERM DEBT
In order to finance the acquisitions discussed above, the Company amended its
reducing revolving line of credit with Bank One. The agreement, as amended,
provides for a $90.0 million reducing revolving line of credit with interest at
LIBOR plus 3.0% and a $25.0 million reducing bridge financing with interest at
LIBOR plus 5.5%. As a result of the payment discussed above, beginning June 1,
2000 through October 1, 2000, the borrowing base reductions were $1.4 million
monthly on the $90.0 million portion and $0.4 million monthly on the $25.0
million portion. The agreement provides for monthly principal payments to the
extent that the loan balance exceeds the borrowing base. In conjunction with the
public offering described in note 2, outstanding borrowings of $63.9 have been
repaid and the borrowing base on the $90.0 million reducing revolving line of
credit has been set at $65.0 million. A new borrowing base reduction schedule
has not yet been set.
(6) EARNINGS PER SHARE
Basic earnings per share is computed by dividing income available to common
stockholders by the weighted average number of common shares outstanding during
the period. On November 17, 1999, as required by the Preferred Stock transaction
discussed in note 9, management and director stockholders placed in escrow
3,304,830 shares of common stock. These shares could not be voted by the
management and director stockholders and all or a portion would only be released
from escrow upon the attainment of specified reserve replacement targets or upon
the completion of an initial public offering. Also, as a requirement of this
transaction, a stockholder returned 3,291,720 shares of common stock which were
cancelled. All of these shares have been excluded from the calculation of
weighted average common shares from November 17, 2000. The effect of the
preferred stock dividends and accretion of issuance costs on arriving at income
available to common stockholders was none in 1999 and $5,974,906 in 2000.
Diluted earnings per share is computed in the same manner as basic earnings per
share except that the denominator is increased to include the number of
additional common shares that could have been outstanding assuming the exercise
of stock options and convertible preferred stock shares and the potential shares
that would have a dilutive effect on earnings per share. The number of dilutive
convertible preferred stock shares and stock awards used in computing diluted
earnings per share were none in 1999 as these securities were antidilutive and
9,528,321 in 2000.
On July 12, 2000, the Board of Directors approved a fifteen hundred-for-one
stock split on the Company's common stock to be effected by the distribution of
fifteen hundred shares for each share outstanding. On September 15, 2000, the
Company increased the number of authorized common shares from 20,000 to
50,000,000 and established a par value of $0.01 per share. All shares
outstanding, per share amounts and par value, have been restated to reflect the
stock split and the establishment of a par value.
(7) STOCK-BASED COMPENSATION
The Company uses the intrinsic value based method of accounting for stock-based
compensation as prescribed by Accounting Principles Board's Opinion No. 25,
"Accounting for Stock Issued to Employees".
In April 2000, an employee, pursuant to their employment agreement, was granted
90,000 shares of restricted stock and stock options to purchase 375,000 shares
of common stock. One-third of the restricted stock granted vested upon the
execution of the employment agreement and one-third will vest on the first and
second anniversary of the agreement. The stock options vest and are exercisable
at the prices as follows: 150,000 shares at $7.67 per share after one year,
150,000 shares at $8.82 per share after two years and the remaining shares at
$10.14 after three years.
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<PAGE> 10
ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
The grant date fair value of the restricted stock and options was estimated to
be $17.00. The Company has recognized non-cash compensation expense in 2000 of
$1,985,148 related to the restricted stock and stock option grants. At September
30, 2000, there was $2,685,852 of deferred stock based compensation expense
related to these awards which will be recognized over the remaining vesting
period.
In November 1999, as a requirement to complete the Preferred Stock transaction
discussed in note 9, management and director stockholders placed in escrow
3,304,830 shares of common stock. These common shares were originally issued for
cash in early 1998, as part of the initial capitalization of the Company, prior
to the commencement of any significant operations by the Company. All or a
portion of these shares were to be released from escrow only upon the attainment
of specified reserve replacement targets or upon completion of a qualifying
public offering. On November 7, 2000, 2,545,500 shares were released as a result
of the public offering and the remaining shares were cancelled. Non-cash
compensation expense in the fourth quarter for the shares released to management
stockholders will be approximately $38.0 million. In addition, at the time of
the initial public offering, the Company awarded 139,500 bonus shares to
employees and will recognize non-cash compensation expense of approximately $2.1
million related to these shares. Compensation expense was calculated using
$15.00 per share, the offering price for the Company's common stock.
(8) HEDGING ACTIVITIES
The Company has entered into 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 utilizes swap and zero-cost collar contracts. To
qualify as a hedge, these contracts must correlate to anticipated future
production such that the Company's exposure to the effects of commodity price
changes is reduced. The gains and losses related to these hedging transactions
are recognized as adjustments to the revenue recorded for the related
production. The Company uses the accrual method of accounting for derivative
commodity instruments. At inception, any contract premiums paid are recorded as
prepaid expenses and, upon settlement of the hedged production month, are
included with the gains and losses on the contracts in oil and gas revenues. As
of September 30, 2000, the Company had contracts maturing monthly through May
2001 related to the net sale of 1,529,000 barrels of crude oil at an average
price of $23.42 per barrel. The effect to the Company to terminate these
contracts at September 30, 2000 was estimated to be a loss of $10.2 million. The
Company had no natural gas hedging positions outstanding.
During October and November 2000, the Company entered into financially-settled
natural gas collar positions maturing monthly from January 2001 through December
2001 related to the net sale of 3,650,000 mmbtu of natural gas with a floor of
$3.00 per mmbtu and a cap of $9.00 per mmbtu.
In June of 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities". Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains or losses) depends on
the intended use of the derivative and resulting designation. If certain
conditions are met, a derivative may be specifically designated as a "fair value
hedge," "cash flow hedge," or a hedge of the foreign currency exposure of a net
investment in a foreign operation. Statement 133 amends and supersedes a number
of existing Statements of Financial Accounting Standards, and nullifies or
modifies the consensus reached in a number of issues addressed by the Emerging
Issues Task Force. Statement 133, as amended, is effective for all fiscal
quarters of fiscal years beginning after June 15, 2000.
-10-
<PAGE> 11
ENERGY PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
The Company will adopt Statement 133 effective January 1, 2001. The Company
expects its oil and gas swap contracts to qualify for hedge accounting treatment
under Statement 133, whereby changes in fair value 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. Any hedge
ineffectiveness will be charged currently to earnings; however, the Company
believes that any ineffectiveness will be immaterial. The effect on earnings and
other comprehensive income as the result of the adoption of Statement 133 will
vary from period to period and will be dependent upon prevailing oil and gas
prices, the volatility of forward prices for oil and gas, the volumes of
production hedged, and the time periods covered by such hedges. The Company does
not expect Statement 133 to have a material impact on the financial statements
as a result of other contractual arrangements that the Company is subject to.
(9) REDEEMABLE PREFERRED STOCK
In November 1999, the Company entered into a stock purchase agreement whereby
600,000 shares of Series A and Series B Preferred Stock were sold for $60.0
million. The Preferred Stock earns cumulative dividends of 10% annually on the
liquidation value of the Series A and Series B Preferred Stock plus dividends in
arrears. At September 30, 2000, there was $5,647,825 of Preferred Stock
dividends in arrears, of which $4,489,944 is Series C Preferred Stock which will
be paid in cash upon conversion. The remaining dividends are Series B Preferred
Stock which will be converted into common stock as a result of the completion of
the initial public offering discussed in note 2. The Company declared and paid
all dividends in arrears immediately prior to the initial public offering.
(10) CONTINGENCIES
The Company has been named as a defendant in certain lawsuits arising in the
ordinary course of business. While the outcome of these lawsuits cannot be
predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position, cash flows or results of
operations of the Company.
Management believes that the Company is in substantial compliance with current
federal, state and local environmental laws, regulations and orders applicable
to it and that continued compliance with existing requirements will not have a
material adverse effect on the Company's financial position, cash flows or
results of operations. There can be no assurance, however, that current
regulatory requirements will not change, currently unforeseen environmental
incidents will not occur or non-compliance with environmental laws or
regulations will not be discovered.
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<PAGE> 12
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.
In March 2000, we acquired Unocal Corporation's 80% interest in South Timbalier
26. In April 2000, we sold to Vastar Resources, Inc. 50% of our working interest
in South Timbalier 26. Additionally, on March 31, 2000, we closed the purchase
of an average 96.1% working interest in the East Bay field from Ocean Energy,
Inc. for $72.3 million.
We have experienced substantial revenue and production growth as a result of the
East Bay and South Timbalier 26 acquisitions. Although the East Bay and South
Timbalier 26 acquisitions had an effective date of January 1, 2000, we reduced
our purchase price on March 31, 2000, by the net cash flows collected by the
sellers (Unocal and Ocean Energy) during the period from January 1, 2000 through
March 31, 2000. Accordingly, we did not include the results of operations from
these acquisitions in our March 31, 2000 operational or financial results, but
only in the pro forma computations.
In September 2000, we closed the acquisition of Texaco Inc.'s 14.6% working
interest in South Timbalier 22, 23 and 27. We acquired this interest effective
January 1, 2000 for a cash price of approximately $2.2 million, net of closing
adjustments.
For the foregoing reasons, the East Bay, South Timbalier 26 and South Timbalier
22, 23 and 27 acquisitions will affect the comparability of our historical
results of operations with results of operations in future periods.
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.
-12-
<PAGE> 13
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 gas operations.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ -----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
NET PRODUCTION (per day):
Oil (Bbls) ..................................... 9,777 945 6,806 1,003
Natural gas (Mcf) .............................. 16,146 2,741 10,819 2,114
Total (Boe) ................................ 12,468 1,402 8,609 1,356
OIL & GAS REVENUES (in thousands):
Oil ............................................ $ 23,545 $ 1,893 $ 48,349 $ 4,505
Natural Gas .................................... 7,091 714 12,297 1,316
Total ...................................... 30,636 2,607 60,646 5,821
AVERAGE SALES PRICES:
Oil (per Bbl)(1) ............................... $ 26.16 $ 21.75 $ 25.92 $ 16.44
Natural gas (per Mcf) .......................... 4.77 2.83 4.15 2.28
Total (per Boe) ............................ 26.71 20.20 25.71 15.73
AVERAGE COSTS (per Boe):
Lease operating expense ........................ $ 5.61 $ 3.15 $ 5.46 $ 2.78
Production taxes ............................... 1.52 -- 1.39 --
Depreciation, depletion, and amortization ...... 6.54 9.17 6.69 8.43
General and administrative expense
(exclusive of stock-based compensation) .... 2.65 4.97 3.12 4.70
</TABLE>
(1) Net of the effect of hedging transactions which reduced oil price
realizations by $4.60 per barrel in the third quarter of 2000 and $3.18 per
barrel for the nine months ended September 30, 2000.
PRODUCTION
CRUDE OIL AND CONDENSATE. Our net oil production for the third quarter of 2000
increased to 9,777 Bbls per day from 945 Bbls per day in the third quarter of
1999. Our net oil production for the first nine months of 2000 increased to
6,806 Bbls per day from 1,003 Bbls per day in the first nine months of 1999.
Both increases were the result of the acquisitions combined with 74 successful
well operations which commenced production after the third quarter of 1999, and
were partially offset by natural declines from other producing wells.
NATURAL GAS. Our net natural gas production for the third quarter of 2000
increased to 16,146 Mcf per day from 2,741 Mcf per day in the third quarter of
1999. Our net natural gas production for the first nine months of 2000 increased
to 10,819 Mcf per day from 2,114 Mcf per day in the first nine months of 1999.
Both increases were the result of the acquisitions combined with 8 successful
well operations which commenced production after the third quarter of 1999, and
were partially offset by natural declines from other producing wells.
-13-
<PAGE> 14
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 third quarter of
2000 was $26.16 per Bbl, an increase of 20% over an average realized price of
$21.75 per Bbl in the third quarter of 1999. Hedging activities in the third
quarter of 2000 reduced oil price realizations by $4.60 per barrel or 15% from
the $30.76 per Bbl that would have otherwise been received. We did not have any
hedging contracts in place in 1999.
Our average realized oil price in the first nine months of 2000 was $25.92 per
Bbl, an increase of 58% over an average realized price of $16.44 per Bbl in the
first nine months of 1999. Hedging activities in the first nine months of 2000
reduced oil price realizations by $3.18 per barrel or 11% from the $29.10 per
Bbl that would have otherwise been received. We did not have any hedging
contracts in place in 1999.
NATURAL GAS. Our average realized natural gas price in the third quarter of 2000
was $4.77 per Mcf, an increase of 69% over an average realized price of $2.83
per Mcf in the third quarter of 1999. Our average realized gas price in the
first nine months of 2000 was $4.15 per Mcf, and increase of 82% over an average
realized price of $2.28 per Mcf in the third quarter of 1999. We had no hedging
positions for natural gas related to 1999 or 2000 production.
NET INCOME AND REVENUES
We recognized net income of $5.2 million in the third quarter of 2000 compared
to a net loss of $0.2 million in the third quarter of 1999. Our oil and natural
gas revenues increased to $30.6 million during the third quarter of 2000, an
increase from $2.6 million in the third quarter of 1999.
We recognized net income of $13.4 million in the first nine months of 2000
compared to a net loss of $0.9 million in the first nine months of 1999. Our oil
and natural gas revenues increased to $60.6 million during the first nine months
of 2000, an increase from $5.8 million in the first nine months of 1999.
The increases in net income and revenues in the three and nine month periods
ended September 30, 2000 were primarily due to sharp increases in commodity
prices coupled with higher production volumes from acquisitions and drilling
activities. The impact of these increases on net income was partially offset by
higher costs associated with increased production volumes.
OPERATING EXPENSES
Operating expenses during the three and nine month periods ended September 30,
2000 were impacted by the following:
o Lease operating expense increased to $6.4 million in the third quarter of
2000 from $0.4 million in the third quarter of 1999. Lease operating
expense increased to $12.9 million in the first nine months of 2000 from
$1.0 million in the first nine months of 1999. The increases were primarily
attributable to the acquisitions and the additional production from 82
successful well operations which commenced production after the third
quarter of 1999.
o Production taxes increased to $1.7 million in the third quarter of 2000
from zero in the third quarter of 1999. Production taxes increased to $3.3
million in the first nine months of 2000 from zero in the first nine months
of 1999. The increases were primarily attributable to the acquisition of
the East Bay field where a portion of the production is subject to
Louisiana severance taxes.
-14-
<PAGE> 15
ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- (CONTINUED)
o Depreciation, depletion and amortization increased to $7.5 million in the
third quarter of 2000 from $1.2 million in the third quarter of 1999.
Depreciation, depletion and amortization increased to $15.8 million in the
first nine months of 2000 from $3.1 million in the first nine months of
1999. The increase in both periods was primarily due to increased
production volumes.
o General and administrative expenses increased to $3.0 million in the third
quarter of 2000 from $0.6 million in the third quarter of 1999. The
increase was primarily due to increased consultant fees ($0.7 million), the
hiring of additional personnel ($2.2 million), increased insurance costs
($0.5 million) and other costs associated with our acquisition of the East
Bay field and the additional interest in the South Timbalier 26 field on
March 31, 2000.
General and administrative expenses increased to $7.4 million in the first
nine months of 2000 from $1.7 million in the first nine months of 1999. The
increase was primarily due to increased consultant fees ($1.8 million), the
hiring of additional personnel ($4.6 million), increased insurance costs
($0.9 million) and partially offset by increased overhead credits received
from joint interest partners, as well as other costs associated with our
acquisition of the East Bay field and the additional interest in the South
Timbalier 26 field on March 31, 2000.
o Non-cash stock-based compensation expense of $0.7 million and $2.0 million
was recognized in the third quarter of 2000 and the first nine months of
2000, respectively, related to the restricted stock and stock option grants
made in April 2000.
OTHER INCOME AND EXPENSE
INTEREST. Interest expense increased to $2.8 million in the third quarter of
2000 from $1.0 million in the third quarter of 1999. Interest expense increased
to $5.8 million in the first nine months of 2000 from $2.3 million in the first
nine months of 1999. The increase in interest expense for the three and nine
month periods ended September 30, 2000 is a result of an increase in long-term
debt outstanding related to our acquisitions.
GAIN ON SALE OF OIL AND GAS ASSETS. On April 20, 2000, we sold a 50% working
interest in the South Timbalier 26 field, resulting in a gain of approximately
$7.8 million. There were no sales for the same period in 1999.
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 recent
acquisitions of the East Bay field, the South Timbalier 22, 23 and 27 interests
and the additional interest in South Timbalier 26 field significantly impacted
our cash flows from operations. Our future cash flow from operations will depend
on our ability to maintain and increase production through our development and
exploration drilling program, as well as the prices of oil and natural gas.
As of September 30, 2000, we had a financing agreement with Energy Income Fund,
a stockholder, under which $10 million was outstanding. The terms of the
agreement require repayment by July 1, 2001.
-15-
<PAGE> 16
ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- (CONTINUED)
In June 1999, we entered into a reducing revolving line of credit of $50.0
million with Bank One, which had a borrowing base of $20.0 million. In March
2000, we entered into a new revolving line of credit with Bank One. The new
agreement provided for a $90.0 million Tranche A reducing revolving line of
credit that terminates March 30, 2003 and a $25.0 million Tranche B reducing
bridge financing that terminates March 30, 2001. Tranche A bears interest at
LIBOR plus 3.0% and Tranche B bears interest at LIBOR plus 5.5%. Beginning June
1, 2000 through October 1, 2000, Tranche A was reduced monthly by $1.4 million
and Tranche B was reduced monthly by $0.4 million. We borrowed $108.0 million
under the credit facility to finance the East Bay and South Timbalier 26
acquisitions. In April 2000, the proceeds from the sale to Vastar were used to
reduce the outstanding balance of the credit facility to $71.8 million.
Subsequent to the repayment of the Tranche B loan, Tranche A will bear interest
at LIBOR plus 1.25% to 2.25%, based on the level of utilization of the line of
credit.
At September 30, 2000, we had $64.0 million of total outstanding debt under our
bank facility and $4.4 million of credit capacity available under this facility.
The Bank One credit facility is secured by substantially all of our assets.
On November 7, 2000, we repaid all amounts due Energy Income Fund and $63.9
million outstanding under the Bank One credit facility with the net $80.2
million in proceeds received from the public offering of 5.75 million shares of
our common stock. As a result of the repayment and a borrowing base
redetermination, we now have $65.0 million of credit capacity available under
our Bank One credit facility.
Net cash of $135.2 million used in investing activities in the first nine months
of 2000 included net oil and gas property capital and exploration expenditures
of $15.9 million and the East Bay, South Timbalier 26 and South Timbalier 22, 23
and 27 acquisitions (prior to the sale to Vastar) of $119.3 million. Exploration
expenditures incurred are excluded from operating cash flows and included in
investing activities. During the first nine months of 2000, we completed 20
drilling projects and 69 recompletion/workover projects, 80 of which were
successful. During the first nine months of 1999, we completed six drilling
projects and 14 recompletion/workover projects, 14 of which were successful.
Cash and cash equivalents at September 30, 2000 were $12.1 million.
Our 2000 capital expenditure budget is focused on exploitation activities on
prospects with multiple reservoirs, which we expect to increase our probability
of success and to lead to accelerated payback of our investment. These
exploitation activities also provide exploratory potential in deeper geologic
formations. We have capital expenditure plans for the last three months of 2000
totaling approximately $23.9 million. Additionally, capital expenditures for
2001 and 2002 are currently estimated to be approximately $134.0 million. Actual
levels of capital expenditures may vary significantly due to many factors,
including drilling results, oil and natural gas prices, industry conditions,
participation by other working interest owners and the prices of drilling rigs
and other oilfield goods and services.
In November 1999, as a requirement to complete the Preferred Stock transaction,
management and director stockholders placed in escrow 3,304,830 shares of common
stock. These common shares were originally issued for cash in early 1998, as
part of the initial capitalization of the Company, prior to the commencement of
any significant operations by the Company. All or a portion of these shares were
to be released from escrow only upon the attainment of specified reserve
replacement targets or upon completion of a qualifying public offering. On
November 7, 2000, 2,545,500 shares were released as a result of the public
offering and the remaining shares were cancelled. Non-cash compensation expense
in the fourth quarter for the shares released to management stockholders will be
approximately $38.0 million. In addition, at the time of the initial public
offering, the Company awarded 139,500 bonus shares to employees and will
recognize non-cash compensation expense of approximately $2.1 million related to
these shares. Compensation expense was calculated using $15.00 per share, the
offering price for the Company's common stock.
-16-
<PAGE> 17
ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- (CONTINUED)
We have experienced and expect to continue to experience substantial working
capital requirements, primarily due to our active capital expenditure program.
We believe that the proceeds from the initial public offering, working capital,
cash flows from operations and borrowings under our credit facility will be
sufficient to meet our capital requirements through the end of 2001. However,
additional financing may be required in the future to fund our growth and
capital expenditures.
HEDGING ACTIVITIES
We have entered into hedging transactions for our oil and natural gas production
to reduce our exposure to fluctuations in the price of oil and natural gas. As
of September 30, 2000, our hedging transactions have to date consisted of
financially-settled crude oil forward sales contracts with major financial
institutions as required by our bank facility entered into in connection with
the acquisitions of the East Bay field and additional interests in the South
Timbalier 26 field. To qualify as a hedge, these contracts must correlate to
anticipated future production such that our exposure to the effects of commodity
price changes is reduced. As of September 30, 2000, we had no natural gas hedge
positions in place.
We financially settle our crude oil forward sales contracts based on the average
of the reported settlement prices for West Texas Intermediate crude on the NYMEX
for each month. With our hedges, the counterparty is required to make a payment
to us if the settlement price for any settlement period is below the hedged
price for the transaction, and we are required to make a payment to the
counterparty if the settlement price for any settlement period is above the
hedged price for the transaction.
The gains and losses related to these hedging transactions are recognized as
adjustments to the revenue recorded for the related production. We use the
accrual method of accounting for derivative commodity instruments. At inception,
any contract premiums paid are recorded as prepaid expenses and, upon settlement
of the hedged production month, are included with the gains and losses on the
contracts in the oil and natural gas revenues.
In October and November 2000, we entered into financially settled zero-cost
collar contracts with major financial institutions pertaining to a portion of
our 2001 projected natural gas production, maturing monthly from January 2001
through December 2001 related to the net sale of 3,650,000 mmbtu of natural gas
with a floor of $3.00 per mmbtu and a cap of $9.00 per mmbtu. To qualify as a
hedge, these contracts must correlate to anticipated future production such that
our exposure to the effects of commodity price changes is reduced. We will
financially settle our natural gas collar contracts based on the average of the
reported settlement prices for Henry Hub natural gas on the NYMEX for the last
three trading days of each month. With our hedges, the counterparty is required
to make a payment to us if the settlement price for any settlement period is
below the 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 for the collar.
We may in the future enter into these and other types of hedging arrangements to
reduce our exposure to fluctuations in the market prices of oil and natural gas.
Hedging transactions expose us to risk of financial loss in some circumstances,
including if production is less than expected, the other party to the contract
defaults on its obligations, or there is a change in the expected differential
between the underlying price in the hedging agreement and actual prices
received. Hedging transactions may limit the benefit we would have otherwise
received from increases in the prices for oil and natural gas. Furthermore, if
we do not engage in hedging transactions, we may be more adversely affected by
declines in oil and natural gas prices than our competitors who engage in
hedging transactions.
Additionally, hedging transactions may expose us to cash margin requirements. We
use primarily over-the-counter hedge instruments with major financial
institutions where margin requirements have been negotiated. Typically, we have
negotiated volumetrically based credit limits where no cash margin is required.
-17-
<PAGE> 18
ENERGY PARTNERS, LTD.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- (CONTINUED)
As of September 30, 2000, we had contracts maturing monthly through May 2001
related to the sale of 1,529,000 barrels of oil at an average price of $23.42
per barrel. Had these contracts been terminated at September 30, 2000, we
estimate the loss would have been $10.2 million. As of September 30, 2000, the
hedged volume approximated 54% of our estimated oil production from proved
reserves through June 2001, and had no natural gas positions outstanding.
NEW ACCOUNTING POLICIES
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities". Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains or losses) depends on
the intended use of the derivative and resulting designation. If certain
conditions are met, a derivative may be specifically designated as a "fair value
hedge," "cash flow hedge," or a hedge of the foreign currency exposure of a net
investment in a foreign operation. Statement 133 amends and supersedes a number
of existing Statements of Financial Accounting Standards, and nullifies or
modifies the consensus reached in a number of issues addressed by the Emerging
Issues Task Force. Statement 133, as amended, is effective for all fiscal
quarters of fiscal years beginning after June 15, 2000.
We will adopt Statement 133 effective January 1, 2001. We expect our oil and gas
swap contracts to qualify for hedge accounting treatment under Statement 133,
whereby changes in fair value 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. Any hedge ineffectiveness will be
charged currently to earnings; however, we believe that any ineffectiveness will
be immaterial. The effect on our earnings and other comprehensive income as the
result of the adoption of Statement 133 will vary from period to period and will
be dependent upon prevailing oil and gas prices, the volatility of forward
prices for oil and gas, the volumes of production hedged, and the time periods
covered by such hedges. We do not expect Statement 133 to have a material impact
on the financial statements as a result of other contractual arrangements that
we are subject to.
FORWARD LOOKING INFORMATION
Any statements made in this document, other than those of historical fact, about
an action, event or development, which the Company hopes, believes or
anticipates may or will occur in the future, are "forward-looking statements"
under U. S. securities laws. Such statements are subject to various assumptions,
risks and uncertainties, which are specifically described in the Company's
prospectus, dated November 1, 2000. Forward-looking statements are not
guarantees of future performance or an assurance that the Company's current
assumptions and projections are valid. Actual results may differ materially from
those projected.
-18-
<PAGE> 19
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. Under our current policies, we do not
use interest rate derivative instruments to manage exposure to interest rate
changes. At September 30, 2000, $64.0 million of our long-term debt had variable
interest rates. This debt has been repaid in November 2000.
COMMODITY PRICE RISK
Our revenues, profitability and future growth depend substantially on prevailing
prices for oil and natural gas. Prices also affect the amount of cash flow
available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under the new credit agreement with
Bank One is subject to periodic redetermination based in part on changing
expectations of future prices. Lower prices may also reduce the amount of oil
and natural gas that we can economically produce. We currently sell all of our
oil and natural gas production under price sensitive or market price contracts.
We use derivative commodity instruments to manage commodity price risks
associated with future oil and natural gas production. Our crude oil commodity
price hedging program uses financially settled crude oil forward sales contracts
and we do not use them for speculative purposes. As of September 30, 2000, we
had contracts maturing monthly through May 2001 related to the sale of 1,529,000
barrels of oil at an average price of $23.42 per barrel. As of September 30,
2000, the hedged volume approximated 54% of our estimated oil production from
proved reserves through June 2001. Had these contracts been terminated at
September 30, 2000, we estimate the loss would have been $10.2 million.
In October and November 2000, we expanded our commodity price hedging program to
include natural gas hedging positions, which utilizes zero-cost collar contracts
and we do not use them for speculative purposes. As of November 20, 2000, we had
contracts maturing monthly from January 2001 through December 2001 related to
the net sale of 3,625,000 mmbtu of natural gas with a floor of $3.00 per mmbtu
and a cap of $9.00 per mmbtu. These positions were not outstanding as of
September 30, 2000.
We use a sensitivity analysis technique to evaluate the hypothetical effect that
changes in the market value of crude oil may have on fair value of our
derivative instruments. At September 30, 2000, the potential change in the fair
value of commodity derivative instruments assuming a 10% adverse movement in the
underlying commodity price is a $4.7 million increase in the deferred cost.
For purposes of calculating the hypothetical change in fair value, the relevant
variables are the type of commodity (crude oil or natural gas), the commodities
futures prices and volatility of commodity prices. The hypothetical fair value
is calculated by multiplying the difference between the hypothetical price and
the contractual price by the contractual volumes.
-19-
<PAGE> 20
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
27 Financial Data Schedule (included only in the electronic
filing of this document)
(b) Reports on Form 8-K:
None.
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: November 30, 2000 By: /s/ SUZANNE V. BAER
------------------------------------------
Suzanne V. Baer
Vice President and Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)
-20-
<PAGE> 21
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
27 Financial Data Schedule (included only in the electronic filing of
this document)
</TABLE>
