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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------------------------------
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 September 30, 2003
OR
[ ] 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
---------------------------------------------
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined by Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
As of October 31, 2003, there were 32,171,880 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
================================================================================
-1-
TABLE OF CONTENTS
Page
----
PART I FINANCIAL STATEMENTS
Item 1. Financial Statements:
Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002.............. 3
Consolidated Statements of Operations for the three and nine months ended
September 30, 2003 and 2002............................................... 4
Consolidated Statements of Cash Flows for the nine months ended September 30, 2003
and 2002.................................................................. 5
Notes to Consolidated Financial Statements ............................................. 6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations... 16
Item 3. Quantitative and Qualitative Disclosures about Market Risk.............................. 22
Item 4. Controls and Procedures................................................................. 23
PART II OTHER INFORMATION
Item 4. Submission of Matters to the Vote of Security Holders................................... 24
Item 6. Exhibits and Reports on Form 8-K........................................................ 24
-2-
ITEM 1. FINANCIAL STATEMENTS
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
September 30, December 31,
2003 2002
------------- ------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 89,539 $ 116
Trade accounts receivable -- net of allowance for
doubtful accounts of $1,351 in 2003 and 2002 30,150 25,824
Deferred tax asset 219 1,221
Prepaid expenses 1,882 1,868
------------- ------------
Total current assets 121,790 29,029
Property and equipment, at cost under the successful efforts
method of accounting for oil and natural gas properties 570,158 471,840
Less accumulated depreciation, depletion and amortization (187,093) (121,034)
------------- ------------
Net property and equipment 383,065 350,806
Other assets 6,151 3,463
Deferred financing costs -- net of accumulated amortization
of $3,035 in 2003 and $2,365 in 2002 4,640 922
------------- ------------
$ 515,646 $ 384,220
============= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 14,560 $ 8,869
Accrued expenses 22,611 43,533
Fair value of commodity derivative instruments 608 3,392
Current maturities of long-term debt 98 92
------------- ------------
Total current liabilities 37,877 55,886
Long-term debt 150,343 103,687
Deferred income taxes 25,575 9,033
Other 41,934 23,692
------------- ------------
255,729 192,298
Stockholders' equity:
Preferred stock, $1 par value, authorized 1,700,000 shares;
368,076 issued and outstanding; aggregate liquidation
value $36,807,590 34,684 35,359
Common stock, par value $0.01 per share. Authorized
50,000,000 shares; issued and outstanding:
2003 - 32,158,936 shares; 2002 - 27,550,466
shares 322 276
Additional paid-in capital 228,383 187,965
Accumulated other comprehensive loss (389) (2,171)
Accumulated deficit (3,083) (29,507)
------------- ------------
Total stockholders' equity 259,917 191,922
Commitments and contingencies
------------- ------------
$ 515,646 $ 384,220
============= ============
See accompanying notes to consolidated financial statements.
-3-
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share data)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Revenue:
Oil and natural gas $ 58,811 $ 33,596 $ 169,911 $ 99,862
Other 68 82 424 (196)
--------- --------- --------- ---------
58,879 33,678 170,335 99,666
--------- --------- --------- ---------
Costs and expenses:
Lease operating 10,671 8,723 28,115 26,067
Taxes, other than on earnings 1,768 1,676 5,919 4,841
Exploration expenditures and dry hole costs 3,999 4,509 9,235 7,949
Depreciation, depletion and amortization 22,341 16,059 59,445 50,317
General and administrative:
Stock-based compensation 340 123 819 327
Severance costs - - - 1,211
Other general and administrative 6,174 4,739 19,164 16,000
--------- --------- --------- ---------
Total costs and expenses 45,293 35,829 122,697 106,712
--------- --------- --------- ---------
Income (loss) from operations 13,586 (2,151) 47,638 (7,046)
--------- --------- --------- ---------
Other income (expense):
Interest income 133 17 179 89
Interest expense (3,120) (1,799) (6,549) (5,237)
--------- --------- --------- ---------
(2,987) (1,782) (6,370) (5,148)
--------- --------- --------- ---------
Income (loss) before income taxes and cumulative
effect of change in accounting principle 10,599 (3,933) 41,268 (12,194)
Income taxes (3,875) 1,377 (15,066) 4,270
--------- --------- --------- ---------
Income (loss) before cumulative effect of change
in accounting principle 6,724 (2,556) 26,202 (7,924)
Cumulative effect of change in accounting principle,
net of income taxes of $1,276 - - 2,268 -
--------- --------- --------- ---------
Net income (loss) 6,724 (2,556) 28,470 (7,924)
Less dividends earned on preferred stock and accretion of
discount (883) (876) (2,691) (2,467)
--------- --------- --------- ---------
Net income (loss) available to common
stockholders $ 5,841 $ (3,432) $ 25,779 $ (10,391)
========= ========= ========= =========
Earnings per share:
Basic:
Before cumulative effect of change in accounting principle $ 0.18 $ (0.12) $ 0.77 $ (0.38)
Cumulative effect of change in accounting principle - - 0.08 -
--------- --------- --------- ---------
Basic earnings (loss) per share $ 0.18 $ (0.12) $ 0.85 $ (0.38)
========= ========= ========= =========
Diluted:
Before cumulative effect of change in accounting principle $ 0.18 $ (0.12) $ 0.75 $ (0.38)
Cumulative effect of change in accounting principle - - 0.06 -
--------- --------- --------- ---------
Diluted earnings (loss) per share $ 0.18 $ (0.12) $ 0.81 $ (0.38)
========= ========= ========= =========
Weighted average common shares used in
computing income (loss) per share:
Basic 32,101 27,509 30,364 27,446
Incremental common shares 4,806 - 4,792 -
--------- --------- --------- ---------
Diluted 36,907 27,509 35,156 27,446
========= ========= ========= =========
See accompanying notes to consolidated financial statements.
-4-
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
Nine Months Ended
September 30,
----------------------
2003 2002
--------- ---------
Cash flows from operating activities:
Net income (loss) $ 28,470 $ (7,924)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Cumulative effect of change in accounting principle, net of tax (2,268) -
Depreciation, depletion and amortization 59,445 50,317
Gain on sale of oil and natural gas assets (207) -
Amortization of deferred revenue - (2,792)
Stock-based compensation 819 327
Deferred income taxes 15,266 (4,270)
Exploration expenditures 6,120 3,982
Non-cash effect of derivative instruments - 514
Amortization of deferred financing costs 670 258
Other 233 -
--------- ---------
108,548 40,412
Changes in operating assets and liabilities, net of acquisition
in 2002:
Trade accounts receivable (4,326) 58
Prepaid expenses (14) 699
Other assets (2,688) (2,097)
Accounts payable and accrued expenses 767 (25,326)
Other liabilities (663) (1,579)
--------- ---------
Net cash provided by operating activities 101,624 12,167
--------- ---------
Cash flows used in investing activities:
Acquisition of business, net of cash acquired (850) (10,661)
Property acquisitions (4,365) (1,142)
Exploration and development expenditures (86,224) (21,778)
Other property and equipment additions (534) (250)
Proceeds from sale of oil and natural gas assets 579 1,069
--------- ---------
Net cash used in investing activities (91,394) (32,762)
--------- ---------
Cash flows provided by financing activities:
Bank overdraft - (808)
Deferred financing costs (4,392) -
Repayments of long-term debt (118,338) (15,519)
Equity offering costs (479) -
Proceeds from public stock offering, net of commissions 38,000 -
Proceeds from senior notes offering 150,000 -
Proceeds from long-term debt 15,000 43,000
Dividends paid (1,304) (1,229)
Exercise of stock options and warrants 706 -
--------- ---------
Net cash provided by financing activities 79,193 25,444
--------- ---------
Net increase in cash and cash equivalents 89,423 4,849
Cash and cash equivalents at beginning of period 116 -
--------- ---------
Cash and cash equivalents at end of period $ 89,539 $ 4,849
========= =========
See accompanying notes to consolidated financial statements.
-5-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 Energy Partners, Ltd.'s (the
Company) Annual Report on Form 10-K for the year ended December 31, 2002 and
Management's Discussion and Analysis of Financial Condition and Results of
Operations. The Company maintains a website at www.eplweb.com which contains
information about the Company including links to the Company's Annual Report on
Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all
related amendments. The Company's website and the information contained in it
and connected to it shall not be deemed incorporated by reference into this
Report on Form 10-Q.
The financial information as of September 30, 2003 and for the three
and nine month periods ended September 30, 2003 and 2002 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) STOCK-BASED COMPENSATION
The Company has two stock award plans, the Amended and Restated 2000
Long Term Stock Incentive Plan and the 2000 Stock Option Plan for Non-Employee
Directors (the Plans). The Company accounts for its stock-based compensation in
accordance with Accounting Principles Board's Opinion No. 25, "Accounting For
Stock Issued to Employees" (Opinion No. 25). Statement of Financial Accounting
Standards No. 123 (Statement 123), "Accounting For Stock-Based Compensation" and
Statement of Financial Accounting Standards No. 148, "Accounting For Stock-Based
Compensation - Transition and Disclosure," (Statement 148) permit the continued
use of the intrinsic value-based method prescribed by Opinion No. 25, but
require additional disclosures, including pro-forma calculations of earnings and
net earnings per share as if the fair value method of accounting prescribed by
Statement 123 had been applied. If compensation expense for the Plans had been
determined using the fair-value method in Statement 123, the Company's net
income (loss) and earnings (loss) per share would have been as follows (in
thousands, except per share amounts):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Net income (loss) available to common stockholders:
As reported ........................................ $ 5,841 $ (3,432) $ 25,779 $ (10,391)
Pro forma .......................................... $ 5,414 $ (4,116) $ 24,780 $ (12,344)
Basic earnings (loss) per share:
As reported ........................................ $ 0.18 $ (0.12) $ 0.85 $ (0.38)
Pro forma .......................................... $ 0.17 $ (0.15) $ 0.82 $ (0.45)
Diluted earnings (loss) per share:
As reported ........................................ $ 0.18 $ (0.12) $ 0.81 $ (0.38)
Pro forma .......................................... $ 0.17 $ (0.15) $ 0.78 $ (0.45)
Stock-option based employee compensation cost,
net of tax, included in net income (loss) as
reported ............................................ $ -- $ 28 $ 28 $ 180
-6-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(3) 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
natural gas exploration and production company with operations focused in the
shallow waters of the Gulf of Mexico. As a result of the acquisition, the
Company has a strengthened management team, expanded exploration opportunities
as well as a reserve portfolio and production that are more balanced between oil
and natural gas.
The acquisition was completed for $38.4 million liquidation preference
of newly authorized and issued Series D Exchangeable Convertible Preferred Stock
(the Series D Preferred Stock), with an issue date fair value of $34.7 million
discounted to give effect to the increasing dividend rate, $38.4 million of 11%
Senior Subordinated Notes (the Notes) due 2009 (immediately callable at par),
574,931 shares of common stock with a fair value of approximately $3.0 million
determined based on the average market price of the Company's common stock over
the period of two days before and after the terms of the acquisition were agreed
to and announced, $9.0 million of cash including $3.9 million of accrued
interest and prepayment fees paid to former debt holders, and warrants to
purchase four million shares of the Company's common stock. Of the warrants, one
million have a strike price of $9.00 and three million have a strike price of
$11.00 per share. The warrants had a fair value of approximately $3.0 million
based on a third party valuation. In addition, the Company incurred
approximately $3.6 million of expenses in connection with the acquisition and
assumed HHOC's working capital deficit.
In addition, former preferred stockholders of HHOC have the right to
receive contingent consideration based upon a percentage of the amount by which
the before tax net present value of proved reserves related, in general, to
exploratory prospect acreage held by HHOC as of the closing date of the
acquisition (the Ring-Fenced Properties) exceeds the net present value
discounted at 30%. The potential consideration is determined annually beginning
March 3, 2003 and ending March 1, 2007. The cumulative percentage remitted to
the participants is 20% for March 3, 2003, 30% for March 1, 2004, 35% for March
1, 2005, 40% for March 1, 2006 and 50% for March 1, 2007. The contingent
consideration, if any, may be paid in the Company's common stock or cash at the
Company's option (with a minimum of 20% in cash) and in no event will exceed a
value of $50 million. On March 17, 2003, the Company capitalized, as additional
purchase price, and paid additional consideration of $0.9 million related to the
March 3, 2003 contingent consideration payment date. Due to the uncertainty
inherent in estimating the value of future contingent consideration which
includes annual revaluations based upon, among other things, drilling results
from the date of the prior revaluation, and development, operating and
abandonment costs and production revenues (actual historical and future
projected, as contractually defined, as of each revaluation date) for the
Ring-Fenced Properties, total final consideration will not be determined until
March 1, 2007. All additional contingent consideration will be capitalized as
additional purchase price.
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.
(4) EARNINGS PER SHARE
Basic earnings per share is computed by dividing income available to
common stockholders by the weighted average number of common shares outstanding
during the period. Diluted earnings per share reflects the potential dilution
that could occur if the Company's convertible preferred stock, options and
warrants were converted to common stock.
The following table reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
the three and nine month periods ended September 30, 2003. The diluted loss per
share calculation for the three and nine months ended September 30, 2002
produces results that are anti-dilutive, therefore, the diluted loss per share
amount
-7-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
as reported for those periods in the accompanying consolidated statements of
operations is the same as the basic loss per share amount.
WEIGHTED
NET INCOME AVERAGE
AVAILABLE COMMON
TO COMMON SHARES EARNINGS
STOCKHOLDERS OUTSTANDING PER SHARE
------------ ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Three months ended September 30, 2003:
Basic..................................................................... $ 5,841 32,101 $ 0.18
Effect of dilutive securities:
Preferred stock..................................................... 883 4,310
Stock options....................................................... -- 330
Warrants............................................................ -- 166
------------ ----------- ---------
Diluted................................................................... $ 6,724 36,907 $ 0.18
WEIGHTED
NET INCOME AVERAGE
AVAILABLE COMMON
TO COMMON SHARES EARNINGS
STOCKHOLDERS OUTSTANDING PER SHARE
------------ ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Nine months ended September 30, 2003:
Basic..................................................................... $ 25,779 30,364 $ 0.85
Effect of dilutive securities:
Preferred stock..................................................... 2,691 4,310
Stock options....................................................... -- 323
Warrants............................................................ -- 159
------------ ----------- ---------
Diluted................................................................... $ 28,470 35,156 $ 0.81
(5) HEDGING ACTIVITIES
The Company enters into hedging transactions with major financial
institutions or counterparties with a credit rating of A or better 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 also uses financially-settled crude oil and natural gas swaps, zero-cost
collars and options that provide floor prices with varying upside price
participation.
With a financially-settled swap, the counterparty is required to make a
payment to the Company if the settlement price for any settlement period is
below the hedged price for the transaction, and the Company is required to make
a payment to the counterparty if the settlement price for any settlement period
is above the hedged price for the transaction. With a zero-cost collar, the
counterparty is required to make a payment to the Company if the settlement
price for any settlement period is below the floor price of the collar, and the
Company is required to make a payment to the counterparty if the settlement
price for any settlement period is above the cap price for the collar. In some
hedges, we have modified our collar to provide full upside participation after a
limited non-participation range.
-8-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The Company had the following hedging contracts as of September 30,
2003:
NATURAL GAS POSITIONS
- -----------------------------------------------------------------------------------------------
VOLUME (Mmbtu)
-------------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/Mmbtu) DAILY TOTAL
- ----------------------- ------------------- ---------------------- -------------------
10/03 - 01/04.......... Collar $3.50/$5.25 10,000 1,230,000
10/03 - 01/04.......... Collar $3.50/$5.40 10,000 1,230,000
02/04 - 12/04.......... Collar $3.50/$8.00 10,000 3,350,000
10/03 - 12/03.......... Combination options $4.19/$6.12/$6.27 20,000 1,840,000
10/03 - 12/03.......... Combination options $4.17/$6.12/$6.27 10,000 920,000
CRUDE OIL POSITIONS
- -----------------------------------------------------------------------------------------------
VOLUME (Bbls)
-------------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/Bbl) DAILY TOTAL
- ----------------------- ------------------- ---------------------- -------------------
10/03 - 12/03.......... Swap $26.36 2,000 184,000
10/03 - 12/03.......... Swap $24.81 1,000 92,000
01/04 - 12/04.......... Swap $27.35 1,500 549,000
01/04 - 06/04.......... Collar $25.00/$31.38 1,500 273,000
07/04 - 09/04.......... Collar $24.00/$29.00 1,500 138,000
Subsequent to September 30, 2003 the Company entered into the following
contracts:
CRUDE OIL POSITIONS
- -----------------------------------------------------------------------------------------------
VOLUME (Bbls)
-------------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/Bbl) DAILY TOTAL
- ----------------------- ------------------- ---------------------- -------------------
10/04 - 12/04.......... Collar $24.00/$28.75 1,500 138,000
Hedging activities reduced natural gas and crude oil revenues by $1.2
million and $10.0 million in the three and nine month periods ended September
30, 2003 and reduced natural gas and crude oil revenues by $1.6 million and $1.7
million in the three and nine month periods ended September 30, 2002.
The following table reconciles the change in accumulated other
comprehensive income for the nine month periods ending September 30, 2003 and
2002:
NINE MONTHS ENDED
SEPTEMBER 30, 2003
(IN THOUSANDS)
--------------------
Accumulated other comprehensive loss as of December 31, 2002 $ (2,171)
Net income............................................................... $ 28,470
Other comprehensive income - net of tax
Hedging activities
Reclassification adjustments for settled contracts ..... 6,416
Changes in fair value of outstanding hedging positions.. (4,634)
--------
Total other comprehensive income............... 1,782 1,782
-------- --------
Comprehensive income..................................................... $ 30,252
========
Accumulated other comprehensive loss as of September 30, 2003 $ (389)
========
NINE MONTHS ENDED
SEPTEMBER 30, 2002
(IN THOUSANDS)
--------------------
Accumulated other comprehensive income as of December 31, 2001 $ 981
Net loss............................................................... $ (7,924)
Other comprehensive loss - net of tax
Hedging activities
Reclassification adjustments for settled contracts.... 1,097
Changes in fair value of outstanding hedging positions (5,168)
--------
Total other comprehensive loss............... (4,071) (4,071)
-------- --------
Comprehensive loss..................................................... $(11,995)
========
Accumulated other comprehensive loss as of September 30, 2002 $ (3,090)
========
-9-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Based upon current prices, the Company expects to transfer
approximately $0.7 million of net deferred losses in accumulated other
comprehensive loss as of September 30, 2003 to earnings during the next twelve
months when the forecasted transactions actually occur.
(6) ASSET RETIREMENT OBLIGATION
In 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations" (Statement 143). Statement 143 requires entities to
record the fair value of a liability for an asset retirement obligation in the
period in which it is incurred, a corresponding increase in the carrying amount
of the related long-lived asset and is effective for fiscal years beginning
after June 15, 2002. The Company adopted Statement 143 effective January 1,
2003, using the cumulative effect approach to recognize transition amounts for
asset retirement obligations, asset retirement costs and accumulated
depreciation. The Company previously recorded estimated costs of dismantlement,
removal, site restoration and similar activities as part of its depreciation,
depletion and amortization for oil and natural gas properties and recorded a
separate liability for such amounts in other liabilities. The effect of adopting
Statement 143 on the Company's results of operations and financial condition
included a net increase in long-term liabilities of $14.2 million; an increase
in net property, plant and equipment of $17.8 million; a cumulative effect of
adoption income of $2.3 million, net of deferred income taxes of $1.3 million.
The following pro forma data summarizes the Company's net loss and net
loss per share as if the Company had adopted the provisions of Statement 143 on
January 1, 2002, including an associated pro forma asset retirement obligation
on that date of $ 33.3 million (in thousands, except per share amounts):
THREE MONTHS NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------- -------------
2002 2002
------------- -------------
Net loss available to common stockholders, as reported.. $ (3,432) $ (10,391)
Pro forma adjustments to reflect retroactive adoption of
Statement 143........................................... (107) (65)
------------- -------------
Pro forma net loss...................................... $ (3,539) $ (10,456)
============= =============
Net loss per share:
Basic - as reported................................... $ (0.12) $ (0.38)
============= =============
Basic - pro forma..................................... $ (0.13) $ (0.38)
============= =============
Diluted - as reported................................. $ (0.12) $ (0.38)
============= =============
Diluted - pro forma................................... $ (0.13) $ (0.38)
============= =============
The following table reconciles the beginning and ending aggregate
recorded amount of the asset retirement obligation for the nine months ended
September 30, 2003 (in thousands):
ASSET
RETIREMENT
OBLIGATION
-----------
December 31, 2002....................................... $ 22,669
Net impact of initial adoption....................... 14,211
Accretion expense.................................... 1,375
Liabilities incurred................................. 387
Liabilities settled.................................. (1,244)
Revisions in estimated cash
flows............................................. 3,437
-----------
September 30, 2003...................................... $ 40,835
===========
(7) NEW ACCOUNTING PRONOUNCEMENTS
In December 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure" (Statement 148). Statement 148 provides alternative methods of
transition for a voluntary change to the fair value based method of
-10-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
accounting for stock-based employee compensation. In addition, Statement 148
amends the disclosure requirements of Statement 123, "Accounting for Stock-Based
Compensation," to require more prominent and frequent disclosures in financial
statements about the effects of stock-based compensation. The transition
guidance and annual disclosure provisions of Statement 148 are effective for
fiscal years ending after December 15, 2002, while the interim disclosure
provisions are effective for periods beginning after December 15, 2002. The
Company is currently assessing the impact of the transition options presented in
Statement 148. The disclosures required by Statement 148 are included in note 2.
On April 30, 2003, the FASB issued Statement of Financial Accounting
Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" (Statement 149). Statement 149 amends and clarifies the
accounting guidance on (1) derivative instruments (including certain derivative
instruments embedded in other contracts) and (2) hedging activities that fall
within the scope of FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities ("Statement 133"). Statement 149 also amends
certain other existing pronouncements, which will result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting. Statement 149 is
effective (1) for contracts entered into or modified after June 30, 2003, with
certain exceptions, and (2) for hedging relationships designated after June 30,
2003. The guidance is to be applied prospectively. The Company has adopted
Statement 149 which did not have a material impact on its financial position or
results of operations or cash flows.
In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity" (Statement 150). Statement 150 establishes
standards for how an issuer classifies and measures in its statement of
financial position certain financial instruments with characteristics of both
liabilities and equity. In accordance with the standard, financial instruments
that embody obligations for the issuer are required to be classified as
liabilities. Statement 150 is effective for financial instruments entered into
or modified after May 31, 2003, and otherwise shall be effective at the
beginning of the first interim period beginning after June 15, 2003. The Company
has adopted Statement 150 which did not have a material impact on its financial
position or results of operations or cash flows.
Statement of Financial Accounting Standards No. 141, "Business
Combinations," and No. 142, "Goodwill and Intangible Assets," became effective
for us on July 1, 2001 and January 1, 2002, respectively. On adoption, the
Company did not believe that these statements changed the existing authoritative
literature specific to accounting for oil and natural gas producing properties.
The Company believes accounting standards setters are currently reviewing the
application of the accounting prescribed by these statements to the oil and
natural gas industry. The result may be to require that mineral use rights, such
as leasehold interests, be separately classified in the balance sheets of oil
and natural gas companies. Specifically these standards may require that mineral
use rights, including proved leaseholds acquired subsequent to June 30, 2001, be
classified on the balance sheet as intangible assets. Accordingly, in a future
filing the Company may be required to reclassify, on the balance sheets
presented, mineral use rights, including leasehold interests, acquired
subsequent to July 1, 2001. The reclassification would result in amounts being
reclassified from "property and equipment" to "intangible acquired proved
leaseholds" and "unproved intangible oil and natural gas properties." At
September 30, 2003 the Company estimates that it had unproved and proved
leaseholds of approximately $6.0 million and $100.0 million that would have
been classified on the balance sheet as unproved intangible oil and natural
gas properties and intangible acquired proved leaseholds, respectively, if the
interpretation currently being deliberated had been applied. The amounts
reclassified from "net property and equipment" would have no effect on
depreciation, depletion and amortization, net income (loss) available to common
stockholders, total assets or total accumulated depreciation, depletion and
amortization for the periods presented.
(8) PUBLIC OFFERING
On April 16, 2003, the Company completed the public offering of
approximately 6.8 million shares of its common stock (the Equity Offering),
which was priced at $9.50 per share. The Equity Offering included 4.2 million
shares offered by the Company, 1.7 million shares offered by Evercore Capital
Partners L.P.
-11-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
and certain of its affiliates, and 0.9 million shares offered by Energy Income
Fund, L.P. In addition, the underwriters exercised their option to purchase 1.0
million additional shares to cover over-allotments, the proceeds from which went
to selling shareholders and not to the Company. After payment of underwriting
discounts and commissions, the offering generated net proceeds to the Company of
approximately $38.0 million. After expenses of approximately $0.4 million, the
proceeds were used to repay a portion of outstanding borrowings under the
Company's bank credit facility.
(9) INDEBTEDNESS
On August 5, 2003, the Company issued $150 million of 8.75% Senior Notes
Due 2010 (the Senior Notes) in a Rule 144A private offering (the Debt Offering)
which allows unregistered transactions with qualified institutional buyers. In
October 2003, the Company consummated an exchange offer pursuant to which it
exchanged registered Senior Notes having substantially identical terms as the
Senior Notes for the privately placed Senior Notes. After discounts and
commissions and estimated offering expenses, the Company received $145.6
million, which was used to redeem all of the outstanding 11% Senior Subordinated
Notes Due 2009 (see note 3) and to repay substantially all of the borrowings
outstanding under the Company's bank credit facility. The remainder of the net
proceeds will be used for general corporate purposes, including acquisitions.
The Senior Notes mature on August 1, 2010 with interest payable each
February 1 and August 1, commencing February 1, 2004. The indenture relating to
the Senior Notes contains certain restrictions on the Company's ability to incur
additional debt, pay dividends on its common stock, make investments, create
liens on its assets, engage in transactions with its affiliates, transfer or
sell assets and consolidate or merge substantially all of its assets. The Senior
Notes are not subject to any sinking fund requirements.
On July 28, 2003 the Company amended its bank credit facility in connection
with the Debt Offering. The amendment reduced the borrowing base under the bank
credit facility to $60 million upon consummation of the Debt Offering. The
borrowing base will remain subject to redetermination based on the proved
reserves of the oil and natural gas properties.
(10) SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In connection with the Debt Offering, discussed above, all of the Company's
current active subsidiaries (the Guarantor Subsidiaries) jointly, severally and
unconditionally guaranteed the payment obligations under the Debt Offering. The
following supplemental financial information sets forth, on a consolidating
basis, the balance sheet, statement of operations and cash flow information for
Energy Partners, Ltd. (Parent Company Only) and for the Guarantor Subsidiaries.
The Company has not presented separate financial statements and other
disclosures concerning the Guarantor Subsidiaries because management has
determined that such information is not material to investors.
The supplemental condensed consolidating financial information has been
prepared pursuant to the rules and regulations for condensed financial
information and does not include all disclosures included in annual financial
statements, although the Company believes that the disclosures made are adequate
to make the information presented not misleading. Certain reclassifications were
made to conform all of the financial information to the financial presentation
on a consolidated basis. The principal eliminating entries eliminate investments
in subsidiaries, intercompany balances and intercompany revenues and expenses.
-12-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET
AS OF SEPTEMBER 30, 2003
(IN THOUSANDS)
PARENT
COMPANY GUARANTOR
ONLY SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents ............... $ 89,539 $ -- $ -- $ 89,539
Trade accounts receivable ............... 24,826 5,324 -- 30,150
Other current assets .................... (8,199) 10,300 -- 2,101
------------ ------------ ------------ ------------
Total current assets ................ 106,166 15,624 -- 121,790
Property and equipment .................... 394,258 175,900 -- 570,158
Less accumulated depreciation, depletion
and amortization ........................ (124,612) (62,481) -- (187,093)
------------ ------------ ------------ ------------
Net property and equipment .......... 269,646 113,419 -- 383,065
Investment in affiliates .................. 93,563 -- (93,563) --
Notes receivable, long-term ............... -- 80,000 (80,000) --
Other assets .............................. 10,791 -- -- 10,791
------------ ------------ ------------ ------------
$ 480,166 $ 209,043 $ (173,563) $ 515,646
============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 36,640 $ 531 $ -- $ 37,171
Fair value of commodity derivative
instruments ........................... 608 -- -- 608
Current maturities of long-term debt .... -- 98 -- 98
------------ ------------ ------------ ------------
Total current liabilities ........... 37,248 629 -- 37,877
Long-term debt ............................ 150,100 80,243 (80,000) 150,343
Other liabilities ......................... 32,901 34,608 -- 67,509
------------ ------------ ------------ ------------
220,249 115,480 (80,000) 255,729
Stockholders' equity
Preferred stock ......................... 34,684 -- -- 34,684
Common stock ............................ 322 -- -- 322
Additional paid-in capital .............. 228,383 -- -- 228,383
Accumulated other comprehensive loss .... (389) -- -- (389)
Accumulated deficit ..................... (3,083) 93,563 (93,563) (3,083)
------------ ------------ ------------ ------------
Total stockholders' equity 259,917 93,563 (93,563) 259,917
------------ ------------ ------------ ------------
$ 480,166 $ 209,043 $ (173,563) $ 515,646
============ ============ ============ ============
-13-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2003
(IN THOUSANDS)
PARENT
COMPANY GUARANTOR
ONLY SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------
Revenue:
Oil and gas ................................. $ 106,405 $ 63,50 $ -- $ 169,911
Other ....................................... 21,724 203 (21,503) 424
------------ ------------ ------------ ------------
128,129 63,709 (21,503) 170,335
Costs and expenses:
Lease operating expenses .................... 14,959 13,156 -- 28,115
Taxes, other than on earnings ............... 946 4,973 -- 5,919
Exploration expenditures .................... 8,935 300 -- 9,235
Depreciation, depletion and amortization .... 44,873 14,572 -- 59,445
General and administrative .................. 19,932 11,301 (11,250) 19,983
------------ ------------ ------------ ------------
Total Operating expenses ................. 89,645 44,302 (11,250) 122,697
Income (loss) from operations ................. 38,484 19,407 (10,253) 47,638
Interest expense, net ......................... (6,347) (23) -- (6,370)
Income before income taxes and cumulative
effect of change in accounting principle .... 32,137 19,384 (10,253) 41,268
Income taxes .................................. (15,066) -- -- (15,066)
------------ ------------ ------------ ------------
Income before cumulative effect of
change in accounting principle ............ 17,071 19,384 (10,253) 26,202
Cumulative effect of change in accounting
principle ................................. 11,399 (9,131) -- 2,268
------------ ------------ ------------ ------------
Net income (loss) ............................. $ 28,470 $ 10,253 $ (10,253) $ 28,470
============ ============ ============ ============
-14-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2003
(IN THOUSANDS)
PARENT
COMPANY GUARANTOR
ONLY SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------
Net cash provided by operating activities $ 82,354 $ 19,270 $ -- $ 101,624
Cash flows used in investing activities:
Acquisition of business, net of cash
acquired .................................. (850) -- -- (850)
Property acquisitions ....................... (4,363) (2) -- (4,365)
Exploration and development
expenditures............................... (67,029) (19,195) -- (86,224)
Other property and equipment
additions ................................. (529) (5) -- (534)
Proceeds from the sale of oil and natural
gas assets ................................ 579 -- -- 579
------------ ------------ ------------ ------------
Net cash used in investing activities ......... (72,192) (19,202) -- (91,394)
Cash flows provided by (used in) financing
activities:
Deferred financing costs .................... (4,391) -- -- (4,391)
Repayments of long-term debt ................ (118,271) (68) -- (118,339)
Equity offering costs ....................... (479) -- -- (479)
Proceeds from public offering net of
commissions ............................... 38,000 -- -- 38,000
Proceeds from senior notes offering ......... 150,000 -- -- 150,000
Proceeds from long-term debt ................ 15,000 -- -- 15,000
Dividends paid .............................. (1,304) -- -- (1,304)
Exercise of stock options and warrants ...... 706 -- -- 706
------------ ------------ ------------ ------------
Net cash provided by (used in) financing
activities .................................. 79,261 (68) -- 79,193
------------ ------------ ------------ ------------
Net increase in cash and cash equivalents ..... 89,423 -- -- 89,423
Cash and cash equivalents at the
beginning of the period ..................... 116 -- -- 116
------------ ------------ ------------ ------------
Cash and cash equivalents at the end of
the period .................................. $ 89,539 $ -- $ -- $ 89,539
============ ============ ============ ============
(11) 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.
(12) RECLASSIFICATIONS
Certain reclassifications have been made to the prior period financial
statements in order to conform to the classification adopted for reporting in
fiscal 2003.
-15-
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, incorporated in January 1998, with operations concentrated in the
shallow to moderate depth waters of the Gulf of Mexico Shelf.
We use the successful efforts method of accounting for our investment in
oil and natural gas properties. Under this method, we capitalize lease
acquisition costs, costs to drill and complete exploration wells in which proven
reserves are discovered and costs to drill and complete development wells.
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 for the fiscal year ended December 31, 2002, includes
a discussion of our critical accounting policies, which have not significantly
changed.
On January 15, 2002, we closed the acquisition of Hall-Houston Oil Company
("HHOC") and certain affiliated interests. At closing, we issued $38.4 million
liquidation preference of newly authorized and issued Series D Exchangeable
Convertible Preferred Stock, with an issue date fair value of $34.7 million,
discounted to effect the increasing dividend rate, $38.4 million of 11% Senior
Subordinated Notes ("the Notes") due 2009 (immediately callable at par) and
574,931 shares of common stock. We also paid $9.0 million of cash including $3.9
million of accrued interest and prepayment fees paid to former debt holders,
assumed HHOC's working capital deficit and issued warrants, with a fair market
value of approximately $3.0 million, to purchase four million shares of common
stock. Former preferred stockholders of HHOC also received the right to receive
contingent consideration related to future proved reserve additions generally to
come from certain exploratory prospect acreage held by HHOC as of the closing
date. We have included the results of operations from the HHOC acquisition with
ours from the closing date of January 15, 2002.
On April 16, 2003, we completed the public offering of 4.2 million
shares of our common stock. The shares were priced at $9.50 per share. After
payment of underwriting discounts and commissions, the offering generated net
proceeds to us of approximately $38.0 million. After expenses of approximately
$0.4 million, the proceeds were used to repay a portion of outstanding
borrowings under our bank credit facility.
On August 5, 2003, we issued $150 million of 8.75% Senior Notes Due
2010 ("the Senior Notes") in a Rule 144A private offering ("the Debt Offering")
which allows unregistered transactions with qualified institutional buyers. In
October 2003, we consummated an exchange offer pursuant to which we exchanged
registered Senior Notes having substantially identical terms as the Senior Notes
for the privately placed Senior Notes. After discounts and commissions and
estimated offering expenses, we received $145.6 million, which was used to
redeem all of our outstanding 11% Senior Subordinated Notes Due 2009 and to
repay substantially all of the borrowings outstanding under our bank credit
facility. The remainder of the net proceeds will be used for general corporate
purposes, including acquisitions.
In October 2003, our principal stockholder, Evercore Capital Partners L.P.,
together with its affiliates ("Evercore"), exercised a contractual right to
request us to register with the SEC for possible public sale all of their
approximately 4.5 million shares of common stock. The registration statement was
declared effective by the SEC on November 4, 2003. Under our Stockholder
Agreement, Evercore is currently entitled to nominate two of our nine directors,
and Evercore's approval is required to take a number of corporate actions. As a
result, Evercore is in a position to control or influence substantially the
manner in which our business is operated. Also under our Stockholder Agreement,
the former HHOC shareholders and our management shareholders each have a right
to nominate one director. Evercore has informed us that it has agreed with its
underwriters to sell all of its shares of our common stock in a public offering,
and expects the offering to close on November 17, 2003. If Evercore successfully
completes this sale, the Stockholder Agreement will terminate, Evercore's
approval will no longer be required for any of our corporate actions, and no
person will have a contractual right to nominate any of our directors.
We amended our bank credit facility in connection with the Debt Offering.
The amendment reduced the borrowing base under our bank credit facility to $60
million upon consummation of the Debt Offering. The borrowing base will remain
subject to redetermination based on the proved reserves of the oil and natural
gas properties.
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.
-16-
RESULTS OF OPERATIONS
The following table presents information about our oil and natural gas
operations.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2003 2002 2003 2002
----------- ----------- ----------- -----------
Net Production (per day):
Oil (Bbls) .................................. 7,841 7,736 7,778 8,555
Natural gas (Mcf) ........................... 86,301 55,166 76,698 55,027
Total barrels of oil equivalent (Boe) ..... 22,225 16,930 20,561 17,726
Oil and Natural Gas Revenues (in thousands):
Oil ......................................... $ 19,364 $ 17,928 $ 59,441 $ 53,883
Natural gas ................................. 39,447 15,668 110,470 45,979
Total oil & natural gas revenues .......... 58,811 33,596 169,911 99,862
Average Sales Prices (1):
Oil (per Bbl) ............................... $ 26.84 $ 25.19 $ 27.99 $ 23.07
Natural gas (per Mcf) ....................... 4.97 3.09 5.28 3.06
Average sales price (per Boe) ............. 28.76 21.57 30.27 20.64
Average Costs (per Boe):
Lease operating expense ..................... $ 5.22 $ 5.60 $ 5.01 $ 5.39
Taxes, other than on earnings ............... 0.86 1.08 1.05 1.00
Depreciation, depletion and amortization .... 10.93 10.31 10.59 10.40
(1) Net of the effect of hedging transactions
PRODUCTION
CRUDE OIL AND CONDENSATE. Our net oil production for the third quarter of
2003 slightly increased to 7,841 Bbls per day from 7,736 Bbls per day in the
third quarter of 2002. The increase was the result of some recompletions
performed on oil wells that slightly increased production and Tropical Storm
Isidore which adversely impacted volumes for the same period in 2002 offset by
natural reservoir declines. Our net oil production for the first nine months of
2003 decreased to 7,778 Bbls per day from 8,555 Bbls per day in the same period
of 2002. The decrease was the result of natural reservoir declines.
NATURAL GAS. Our net natural gas production for the third quarter of 2003
increased to 86,301 Mcf per day from 55,166 Mcf per day in the third quarter of
2002. Our net natural gas production for the first nine months of 2003 increased
to 76,698 Mcf per day from 55,027 Mcf per day in the same period of 2002. The
increase was the result of new production from 14 natural gas wells, primarily
in federal waters, completed and brought on production subsequent to the third
quarter 2002, the storm impact discussed above and partially offset by natural
reservoir declines.
REALIZED PRICES
CRUDE OIL AND CONDENSATE. Our average realized oil price in the third
quarter of 2003 was $26.84 per Bbl, an increase of 7% from an average realized
price of $25.19 per Bbl in the third quarter of 2002. Hedging activities reduced
oil price realizations by $1.55 per Bbl or 5% from the $28.39 per Bbl that would
have otherwise been received in the third quarter of 2003. In the third quarter
of 2002, hedging activities reduced oil price realizations by $1.01 per Bbl or
4% from the $26.20 per Bbl that would have otherwise been received.
Our average realized oil price in the first nine months of 2003 was $27.99
per Bbl, an increase of 21% from an average realized price of $23.07 per Bbl in
the first nine months of 2002. Hedging activities reduced oil price realizations
by $1.59 per Bbl or 5% from the $29.58 per Bbl that would have otherwise been
received in the first nine months of 2003. In the first nine months of 2002,
hedging activities reduced oil price realizations by $0.44 per Bbl or 2% from
the $23.51 per Bbl that would have otherwise been received.
-17-
NATURAL GAS. Our average realized natural gas price in the third quarter of
2003 was $4.97 per Mcf, an increase of 61% from an average realized price of
$3.09 per Mcf in the third quarter of 2002. Hedging activities reduced natural
gas price realizations by $0.02 per Mcf from the $4.99 per Mcf that would have
otherwise been received in the third quarter of 2003. Hedging activities reduced
natural gas price realizations by $0.17 per Mcf or 5% from the $3.26 per Mcf
that would have otherwise been received in the third quarter of 2002.
Our average realized natural gas price in the first nine months of 2003 was
$5.28 per Mcf, an increase of 73% over an average realized price of $3.06 per
Mcf in the first nine of 2002. In the first nine months of 2003, hedging
activities decreased natural gas price realizations by $0.32 or 6% per Mcf from
the $5.60 per Mcf that would have otherwise been received. In the first nine
months of 2002, hedging activities decreased natural gas price realizations by
$0.04 per Mcf from $3.10 per Mcf that would have otherwise been received.
NET INCOME AND REVENUES
Our oil and natural gas revenues increased to $58.8 million in the third
quarter of 2003 from $33.6 million in the third quarter of 2002. The significant
increase for this period is the result of the 31% increase in our Boe production
volume and increased prices previously discussed.
Our oil and natural gas revenues increased to $169.9 million in the first
nine months of 2003 from $99.9 million in the first nine months of 2002. The
significant increase in this nine month period is a result of a Boe production
volume increase of 16%, combined with an increase in oil and natural gas prices
that was more significant than that experienced in the current quarter.
We recognized net income of $6.7 million in the third quarter of 2003
compared to a net loss of $2.6 million in the third quarter of 2002. We
recognized net income of $28.5 million in the first nine months of 2003 compared
to a net loss of $7.9 million in the first nine months of 2002. The increase in
net income was primarily due to the increase in oil and natural gas revenues
previously discussed and partially offset by higher operating costs. In
addition, the following items had a significant impact on our net income or loss
in these periods and affect the comparability of the results of operations for
the periods:
- In January 2003, we adopted the Financial Accounting Standards Boards'
Statement 143, Accounting for Asset Retirement Obligations, using the
cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated
depreciation. We previously recorded estimated costs of dismantlement,
removal, site restoration and similar activities as part of our
depreciation, depletion and amortization for oil and natural gas
properties and recorded a separate liability for such amounts in other
liabilities. The effect of adopting Statement 143 on the results of
operations for the nine months ended September 30, 2003 included a
cumulative effect of adoption income of $2.3 million net of deferred
income taxes.
- In March 2002, in connection with management's plan to reduce costs and
effectively combine the operations of HHOC with ours, we executed a
severance plan and recorded an expense of $1.2 million.
OPERATING EXPENSES
Operating expenses during the three and nine month periods ended September 30,
2003 and 2002 were affected by the following:
- Lease operating expense increased to $10.7 million in the third quarter of
2003 from $8.7 million in the third quarter of 2002. This is a result of
the addition of production from new fields, whereas the majority of our
new production in the past was primarily from our large fields with
existing infrastructure and lower variable cost.
Lease operating expense increased to $28.1 million in the first nine
months of 2003 from $26.1 million in the first nine months of 2002. The
increase is due to the reason discussed above combined with higher than
expected cost on non-operated fields.
-18-
- Taxes, other than on earnings increased to $1.8 million in the third
quarter of 2003 from $1.7 million in the third quarter of 2002. Taxes,
other than on earnings increased to $5.9 million in the first nine months
of 2003 from $4.8 million in the first nine months of 2002. The increases
were due to increases in the production volumes and prices received for
our oil and natural gas production on state leases, primarily at East Bay
and Bay Marchand, subject to Louisiana severance taxes.
- Depreciation, depletion and amortization increased to $22.3 million in the
third quarter of 2003 from $16.1 million in the third quarter of 2002.
Depreciation, depletion and amortization increased to $59.4 million in the
first nine months of 2003 from $50.3 million in the first nine months of
2002. The increases in both periods were due to the increased depreciable
asset base combined with higher production and a shift in the production
contribution from our various fields.
- Other general and administrative expenses increased to $6.2 million in the
third quarter of 2003 from $4.7 million in the third quarter of 2002. The
increase was primarily due to increased personnel costs ($0.8 million) and
increased insurance costs ($0.6 million).
Other general and administrative expenses increased to $19.2 million in
the first nine months of 2003 from $16.0 million in the first nine months
of 2002. The increase was primarily due to additional personnel costs
($3.4 million) and increased insurance costs ($0.5 million), offset by
eliminating redundant costs in the Houston and New Orleans offices and
decreases in various other costs.
- As previously discussed, $1.2 million of severance costs were incurred in
the first nine months of 2002 in connection with the HHOC acquisition.
Management assessed the personnel needs of the combined companies and
implemented a plan to terminate 14 employees.
- Non-cash stock-based compensation expense of $0.3 million was recognized
in the third quarter of 2003 compared to $0.1 million in the third quarter
of 2002. Non-cash stock-based compensation expense of $0.8 million was
recognized in the first nine months of 2003 compared to $0.3 million
recognized in the first nine months of 2002. The expense relates to
restricted stock performance share awards and stock option grants made to
employees.
OTHER INCOME AND EXPENSE
INTEREST. Interest expense increased to $3.1 million in the third quarter
of 2003 from $1.8 million in the third quarter of 2002. Interest expense for the
year to date period increased to $6.5 million in 2003 from $5.2 million in 2002.
The increase was a result of interest expense on the 8.75% Senior Notes issued
in August 2003 partially offset by the interest savings from the redemption of
the Notes and the repayment of the bank credit facility.
LIQUIDITY AND CAPITAL RESOURCES
We intend to use cash flows from operations before changes in working
capital to fund our future capital expenditure program. Our future cash flows
from operations before changes in working capital will depend on our ability to
maintain and increase production through our development and exploratory
drilling program, as well as the prices we receive for oil and natural gas. We
may, from time to time, use the availability of our bank credit facility for
working capital needs.
Our bank credit facility, as amended on July 28, 2003, consists of a
revolving line of credit with a group of banks available through March 30, 2005
(the "bank credit facility"). The bank credit facility currently has a borrowing
base of $60 million that is subject to redetermination based on the proved
reserves of the oil and natural gas properties that serve as collateral for the
bank credit facility as set out in the reserve report delivered to the banks
each April 1 and October 1. As of September 30, 2003 we had $59.9 million
available under the bank credit facility. The bank credit 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 credit
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 credit facility is secured by
substantially all of our oil and natural gas assets. In addition, we pay an
annual fee on the unused portion of the bank credit facility ranging between
..375% to .5% depending on the utilization of our borrowing base. The bank credit
facility contains customary events of default and requires
-19-
that we satisfy various financial covenants.
On August 5, 2003, we issued, in a private placement, $150 million of 8.75%
Senior Notes due 2010. The Senior Notes bear interest at a rate of 8.75% per
annum with interest payable semi-annually on February 1 and August 1, beginning
February 1, 2004. We may redeem the notes at our option, in whole or in part, at
any time on or after August 1, 2007 at a price equal to 100% of the principal
amount plus accrued and unpaid interest, if any, plus a specified premium which
decreases yearly from 4.375% in 2007 to 0% in 2009 and thereafter. In addition,
at any time prior to August 1, 2006, we may redeem up to a maximum of 35% of the
aggregate principal amount with the net proceeds of certain equity offerings at
a price equal to 108.75% of the principal amount, plus accrued and unpaid
interest. The notes are unsecured obligations and rank equal in right of payment
to all existing and future senior debt, including the bank credit facility, and
will rank senior or equal in right of payment to all existing and future
subordinated indebtedness. The Senior Notes were effectively registered with the
Securities and Exchange Commission in October 2003 at 100% of principal amount.
Upon closing on the Senior Notes on August 5, 2003, we called our $38.4
million 11% notes due 2009 for redemption. The redemption of the Notes in
aggregate principal and accrued interest were funded with a portion of the
proceeds received from the Senior Notes and was completed in August 2003. The
Notes were issued on January 15, 2001 as part of the acquisition of HHOC and
bore interest at a rate of 11% per annum with interest payable semi-annually on
January 15 and July 15. In addition, $39.9 million of the proceeds from the
Senior Notes were used to pay substantially all of the borrowings under the bank
credit facility. As a result of the issuance of the Senior Notes, our bank
credit facility borrowing base was reduced from $100 million to $60 million
requiring a non-cash charge of $0.3 million for the write-off of the pro rata
remaining balance of unamortized issue costs.
Net cash of $91.4 million used in investing activities in the first nine
months of 2003 consisted primarily of oil and natural gas property capital and
exploration expenditures. Dry hole costs resulting from exploration expenditures
are excluded from operating cash flows and included in investing activities.
During the first nine months of 2003, we completed 11 drilling projects, 8 of
which were successful and 26 recompletion/workover projects, 23 of which were
successful. During the first nine months of 2002, we completed five drilling
projects, four of which were successful and 21 recompletion/workover projects,
16 of which were successful.
Our 2003 capital expenditure budget is focused on exploration, exploitation
and development activities on our proved properties combined with moderate risk
and higher risk exploratory activities on undeveloped leases. We currently
intend to allocate approximately 65% of our budget on an annual basis to low
risk development and exploitation activities, approximately 25% to moderate risk
exploration opportunities and approximately 10% to higher risk, higher potential
exploration opportunities. Our capital expenditure budget for 2003 is
approximately $110 million. During the first nine months of 2003, capital
expenditures were approximately $74.4 million. The level of our capital
expenditure budget is based on many factors, including results of our drilling
program, oil and natural gas prices, industry conditions, participation by other
working interest owners and the costs of drilling rigs and other oilfield goods
and services. Should actual conditions differ materially from expectations, some
projects may be accelerated or deferred and, consequently, may increase or
decrease total 2003 capital expenditures.
We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active capital expenditure
program. We believe that cash flows from operations before changes in working
capital will be sufficient to meet our capital requirements for at least the
next twelve months. Availability under the bank credit facility will be used to
balance short-term fluctuations in working capital requirements. However,
additional financing may be required in the future to fund our growth.
Our annual report on Form 10-K for the year ended December 31, 2002
included a discussion of our contractual obligations; the only changes to that
disclosure during the nine months ended September 30, 2003 is the decrease in
borrowings under our bank credit facility, redemption of all of the Notes and
the issuance of the Senior Notes, discussed herein.
-20-
NEW ACCOUNTING PRONOUNCEMENTS
In December 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure" ("Statement 148"). Statement 148 provides alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, Statement 148 amends the
disclosure requirements of Statement 123, "Accounting for Stock-Based
Compensation," to require more prominent and frequent disclosures in financial
statements about the effects of stock-based compensation. The transition
guidance and annual disclosure provisions of Statement 148 are effective for
fiscal years ending after December 15, 2002, while the interim disclosure
provisions are effective for periods beginning after December 15, 2002. We are
currently assessing the impact of the transition options presented in Statement
148. The disclosure provisions required by Statement 148 are included in note 2
of the financial statements.
On April 30, 2003, the FASB issued Statement of Financial Accounting
Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" ("Statement 149"). Statement 149 amends and clarifies the
accounting guidance on (1) derivative instruments (including certain derivative
instruments embedded in other contracts) and (2) hedging activities that fall
within the scope of FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities ("Statement 133"). Statement 149 also amends
certain other existing pronouncements, which will result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting. Statement 149 is
effective (1) for contracts entered into or modified after June 30, 2003, with
certain exceptions, and (2) for hedging relationships designated after June 30,
2003. The guidance is to be applied prospectively. We have adopted Statement 149
which did not have a material impact on our financial position or results of
operations or cash flows.
In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity" ("Statement 150"). Statement 150 establishes
standards for how an issuer classifies and measures in its statement of
financial position certain financial instruments with characteristics of both
liabilities and equity. In accordance with the standard, financial instruments
that embody obligations for the issuer are required to be classified as
liabilities. Statement 150 is effective for financial instruments entered into
or modified after May 31, 2003, and otherwise shall be effective at the
beginning of the first interim period beginning after June 15, 2003. We have
adopted Statement 150 which did not have a material impact on our financial
position or results of operations or cash flows.
Statement of Financial Accounting Standards No. 141, "Business
Combinations," and No. 142, "Goodwill and Intangible Assets," became effective
for us on July 1, 2001 and January 1, 2002, respectively. On adoption, we did
not believe that these statements changed the existing authoritative literature
specific to accounting for oil and natural gas producing properties. We believe
accounting standards setters are currently reviewing the application of the
accounting prescribed by these statements to the oil and natural gas industry.
The result may be to require that mineral use rights, such as leasehold
interests, be separately classified in the balance sheets of oil and natural gas
companies. Specifically these standards may require that mineral use rights,
including proved leaseholds acquired subsequent to June 30, 2001, be classified
on the balance sheet as intangible assets. Accordingly, in a future filing we
may be required to reclassify, on the balance sheets presented, mineral use
rights, including leasehold interests, acquired subsequent to July 1, 2001. The
reclassification would result in amounts being reclassified from "property and
equipment" to "intangible acquired proved leaseholds" and "unproved intangible
oil and natural gas properties." At September 30, 2003 we estimate that we had
unproved and proved leaseholds of approximately $6.0 million and $100.0 million
that would have been classified on the balance sheet as unproved intangible oil
and natural gas properties and intangible acquired proved leaseholds,
respectively, if the interpretation currently being deliberated had been
applied. The amounts reclassified from "net property and equipment" would have
no effect on depreciation, depletion and amortization, net income (loss)
available to common stockholders, total assets or total accumulated
depreciation, depletion and amortization for the periods presented.
-21-
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, 2002. 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.
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 bank credit facility. Under our current
policies, we do not use interest rate derivative instruments to manage exposure
to interest rate changes. At September 30, 2003, $0.1 million of our long-term
debt had variable interest rates, while the remaining long-term debt had fixed
interest rates, therefore an increase in the variable interest rate would not
have a material impact on net income.
COMMODITY PRICE RISK
Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and natural gas. Prices also affect the amount of cash
flow available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under the bank credit facility is
subject to periodic redetermination based in part on changing expectations of
future prices. Lower prices may also reduce the amount of oil and natural gas
that we can economically produce. We currently sell all of our oil and natural
gas production under price sensitive or market price contracts.
We use derivative commodity instruments to manage commodity price risks
associated with future oil and natural gas production. As of September 30, 2003,
we had the following contracts in place:
NATURAL GAS POSITIONS
- --------------------------------------------------------------------------------------------------
VOLUME (Mmbtu)
--------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/Mmbtu) DAILY TOTAL
----------------------- ------------- ---------------------- ----- -----
10/03 - 01/04............. Collar $3.50/$5.25 10,000 1,230,000
10/03 - 01/04............. Collar $3.50/$5.40 10,000 1,230,000
02/04 - 12/04............. Collar $3.50/$8.00 10,000 3,350,000
10/03 - 12/03............. Combination options $4.19/$6.12/$6.27 20,000 1,840,000
10/03 - 12/03............. Combination options $4.17/$6.12/$6.27 10,000 920,000
CRUDE OIL POSITIONS
- -------------------------------------------------------------------------------------------------
VOLUME (Bbls)
-------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/Bbl) DAILY TOTAL
----------------------- ------------- -------------------- ----- -----
10/03 - 12/03............. Swap $26.36 2,000 184,000
10/03 - 12/03............. Swap $24.81 1,000 92,000
01/04 - 12/04............. Swap $27.35 1,500 549,000
01/04 - 06/04............. Collar $25.00/$31.38 1,500 273,000
07/04 - 09/04............. Collar $24.00/$29.00 1,500 138,000
-22-
Subsequent to September 30, 2003 the Company entered into the following
contracts:
CRUDE OIL POSITIONS
- -------------------------------------------------------------------------------------------------
VOLUME (Bbls)
-------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/Bbl) DAILY TOTAL
----------------------- ------------- -------------------- ----- -----
10/04 - 12/04............. Collar $24.00/$28.75 1,500 138,000
Our hedged volume as of September 30, 2003 approximated 33% of our
estimated production from proved reserves for the balance of the terms of the
contracts.
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
the fair value of our derivative instruments. At September 30, 2003, the
potential change in the fair value of commodity derivative instruments assuming
a 10% adverse movement in the underlying commodity price was a $6.2 million
increase in the combined estimated loss.
For purposes of calculating the hypothetical change in fair value, the
relevant variables are the type of commodity (crude oil or natural gas), the
commodities futures prices and volatility of commodity prices. The hypothetical
fair value is calculated by multiplying the difference between the hypothetical
price and the contractual price by the contractual volumes.
ITEM 4. CONTROLS AND PROCEDURES
Under the supervision and with the participation of certain members of the
Company's management, including the Chief Executive Officer and Chief Financial
Officer, the Company completed an evaluation of the effectiveness of its
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
to the Securities Exchange Act of 1934, as amended). Based on this evaluation,
the Company's Chief Executive Officer and Chief Financial Officer believe that
the disclosure controls and procedures were effective as of the end of the
period covered by this report with respect to timely communication to them and
other members of management responsible for preparing periodic reports and all
material information required to be disclosed in this report as it relates to
the Company and its consolidated subsidiaries. There was no change in the
Company's internal control over financial reporting during the Company's last
fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the Company's internal control over financial reporting.
The Company's management, including the Chief Executive Officer and Chief
Financial Officer, does not expect that our disclosure controls and procedures
or our internal controls will prevent all errors and all fraud. A control
system, no matter how well conceived and operated, can provide only reasonable,
not absolute, assurance that the objectives of the control system are met.
Further, the design of a control system must reflect the fact that there are
resource constraints, and the benefits of controls must be considered relative
to their costs. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within the company have been detected. These
inherent limitations include the realities that judgments in decision-making can
be faulty, and that breakdowns can occur because of simple error or mistake.
Additionally, controls can be circumvented by the individual acts of some
persons or by collusion of two or more people. The design of any system of
controls also is based in part upon certain assumptions about the likelihood of
future events, and there can be no assurance that any design will succeed in
achieving its stated goals under all potential future conditions; over time,
controls may become inadequate because of changes in conditions, or the degree
of compliance with the policies or procedures may deteriorate. Because of the
inherent limitations in a cost-effective control system, misstatements due to
error or fraud may occur and not be detected. Accordingly, our disclosure
controls and procedures are designed to provide reasonable, not absolute,
assurance that the objectives of our disclosure control system are met and, as
set forth above, our chief executive officer and chief financial officer have
concluded, based on their evaluation as of the end of the period, that our
disclosure controls and procedures were sufficiently effective to provide
reasonable assurance that the objectives of our disclosure control system were
met.
-23-
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO THE VOTE OF SECURITY HOLDERS
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
10.1 Amendment No. 1 to Registration Rights Agreement between Energy
Partners, Ltd., and Evercore Capital Partners L.P., Evercore Capital
Partners (NQ) L.P. and Evercore Capital Offshore Partners L.P., Energy
Income Fund, L.P., and certain individual shareholders of the Company
effective November 3, 2003.
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chairman, President, and
Chief Executive Officer of Energy Partners, Ltd.
31.2 Rule 13a-14(c)/15d-14(a) Certification of Executive Vice President and
Chief Financial Officer of Energy Partners, Ltd.
32.0 Section 1350 Certifications.
(b) Reports on Form 8-K:
On July 3, 2003 the Company filed/furnished a current report on Form
8-K, reporting, under Items 5 and 9, conformation with the transition
provisions of Financial Accounting Standards Board (FASB) Statement
143, Accounting for Asset Retirement Obligations (Statement 143) and
the issuance of a press release announcing two additional exploratory
successes and updating production guidance for the second quarter of
2003.
On August 8, 2003 the Company filed a current report on Form 8-K,
reporting, under Items 5 and 7, the agreement of Evercore Capital
Partners, L.P. to sell 2,500,000 shares of the Company's common stock
and enclosing the underwriting agreement dated August 7, 2003.
-24-
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 12, 2003 By: /s/ SUZANNE V. BAER
------------------------------------------------
Suzanne V. Baer
Executive Vice President and Chief Financial
Officer (Authorized Officer and Principal
Financial Officer)
-25-
EXHIBIT INDEX
Exhibit
Number Description of Exhibit
- ------ ----------------------
10.1 Amendment No. 1 to Registration Rights Agreement between
Energy Partners, Ltd., and Evercore Capital Partners L.P.,
Evercore Capital Partners (NQ) L.P. and Evercore Capital
Offshore Partners L.P., Energy Income Fund, L.P., and certain
individual shareholders of the Company effective November 3,
2003.
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chairman, President,
and Chief Executive Officer of Energy Partners, Ltd.
31.2 Rule 13a-14(a)/15d-14(a) Certification of Executive Vice
President and Chief Financial Officer of Energy Partners, Ltd.
32.0 Section 1350 Certifications.
-26-