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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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)
700 Louisiana, Suite 2100 Houston, Texas 77002
(Address of temporary principal executive offices) (Zip code)
Registrant's telephone number, including area code: (713) 228-0711
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Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act). Yes[ ] No [X]
As of November 4, 2005, there were 37,979,413 shares of the Registrant's
Common Stock, par value $0.01 per share, outstanding.
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1
TABLE OF CONTENTS
Page
----
PART I FINANCIAL STATEMENTS
Item 1. Financial Statements:
Consolidated Balance Sheets as of September 30, 2005 and
December 31, 2004........................................ 3
Consolidated Statements of Operations for the three and nine
months ended September 30, 2005 and 2004................. 4
Consolidated Statements of Cash Flows for the nine months
ended September 30, 2005 and 2004........................ 5
Notes to Consolidated Financial Statements ................. 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................ 17
Item 3. Quantitative and Qualitative Disclosures about Market
Risk..................................................... 24
Item 4. Controls and Procedures..................................... 26
PART II OTHER INFORMATION
Item 6. Exhibits.................................................... 27
2
ITEM 1. FINANCIAL STATEMENTS
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
September 30, December 31,
2005 2004
------------- ------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents ............................................. $ 51,011 $ 93,537
Trade accounts receivable ............................................. 45,754 59,341
Other receivables ..................................................... 12,422 5,600
Deferred tax assets ................................................... 10,306 1,906
Prepaid expenses ...................................................... 4,461 2,285
---------- ---------
Total current assets ............................................ 123,954 162,669
Property and equipment, at cost under the successful efforts
method of accounting for oil and natural gas properties ............... 1,155,726 769,331
Less accumulated depreciation, depletion and amortization ................ (389,834) (304,997)
---------- ---------
Net property and equipment ...................................... 765,892 464,334
Other assets ............................................................. 16,811 15,970
Deferred financing costs -- net of accumulated amortization
of $4,920 in 2005 and $4,174 in 2004 .................................. 4,391 4,705
---------- ---------
$ 911,048 $ 647,678
========== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ...................................................... $ 47,050 $ 21,255
Accrued expenses ...................................................... 118,365 59,387
Fair value of commodity derivative instruments ........................ 26,502 1,749
Current maturities of long-term debt .................................. 137 108
---------- ---------
Total current liabilities ....................................... 192,054 82,499
Long-term debt ........................................................... 225,000 150,109
Deferred tax liabilities ................................................. 73,787 53,686
Asset retirement obligation .............................................. 54,093 45,064
Other .................................................................... 12,981 1,271
---------- ---------
557,915 332,629
Stockholders' equity:
Preferred stock, $1 par value. Authorized 1,700,000 shares;
issued and outstanding: 2005 - no shares; 2004 - 344,399
shares. Aggregate liquidation value: 2004 - $34,440 ................ -- 33,504
Common stock, par value $0.01 per share. Authorized 50,000,000
shares; issued and outstanding: 2005 - 41,445,697 shares;
2004 - 36,618,084 shares ........................................... 415 367
Additional paid-in capital ............................................ 347,289 296,460
Accumulated other comprehensive loss -- net of deferred taxes of
$13,726 in 2005 and $630 in 2004 ................................... (24,402) (1,119)
Retained earnings ..................................................... 87,263 43,215
Treasury stock, at cost. 2005 -- 3,474,208 shares; 2004 -- 3,480,441
shares ............................................................. (57,432) (57,378)
---------- ---------
Total stockholders' equity ...................................... 353,133 315,049
Commitments and contingencies
---------- ---------
$ 911,048 $ 647,678
========== =========
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,
------------------ -------------------
2005 2004 2005 2004
------- ------- -------- --------
Revenue:
Oil and natural gas ........................................... $91,977 $73,997 $295,660 $212,393
Other ......................................................... 72 120 23 263
------- ------- -------- --------
92,049 74,117 295,683 212,656
------- ------- -------- --------
Costs and expenses:
Lease operating ............................................... 14,163 10,550 40,720 29,909
Transportation expense ........................................ 288 59 793 276
Taxes, other than on earnings ................................. 2,836 2,129 8,258 6,449
Exploration expenditures and dry hole costs ................... 23,313 9,998 52,940 26,930
Depreciation, depletion and amortization ...................... 26,278 25,309 79,430 66,261
General and administrative:
Stock-based compensation ................................... 2,460 1,035 6,217 2,554
Other general and administrative ........................... 7,761 6,656 24,066 20,406
------- ------- -------- --------
Total costs and expenses ................................ 77,099 55,736 212,424 152,785
------- ------- -------- --------
Income from operations ........................................... 14,950 18,381 83,259 59,871
------- ------- -------- --------
Other income (expense):
Interest income ............................................... 223 322 518 785
Interest expense .............................................. (4,929) (3,602) (13,312) (10,762)
------- ------- -------- --------
(4,706) (3,280) (12,794) (9,977)
------- ------- -------- --------
Income before income taxes .............................. 10,244 15,101 70,465 49,894
Income taxes ..................................................... (3,724) (5,532) (25,474) (18,223)
------- ------- -------- --------
Net income .............................................. 6,520 9,569 44,991 31,671
Less dividends earned on preferred stock and accretion of
discount and issuance costs ................................... -- (823) (944) (2,573)
------- ------- -------- --------
Net income available to common stockholders ............. $ 6,520 $ 8,746 $ 44,047 $ 29,098
======= ======= ======== ========
Basic earnings per share ...................................... $ 0.17 $ 0.27 $ 1.20 $ 0.89
======= ======= ======== ========
Diluted earnings per share .................................... $ 0.16 $ 0.25 $ 1.11 $ 0.82
======= ======= ======== ========
Weighted average common shares used in Computing income per share:
Basic ......................................................... 37,779 32,992 36,798 32,788
Incremental common shares
Preferred stock ............................................ -- 4,057 727 4,056
Stock options .............................................. 846 671 915 571
Warants .................................................... 2,077 1,141 1,964 990
Restricted share units ..................................... 243 43 206 36
------- ------- -------- --------
Diluted ....................................................... 40,945 38,904 40,610 38,441
======= ======= ======== ========
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,
---------------------
2005 2004
--------- ---------
Cash flows from operating activities:
Net income ................................................ $ 44,991 $ 31,671
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ............ 79,430 66,261
Loss on disposition of oil and natural gas assets ... 92 --
Non cash-based compensation ......................... 6,267 2,603
Deferred income taxes ............................... 25,128 18,072
Exploration expenditures ............................ 41,208 19,540
Amortization of deferred financing costs ............ 746 682
Other ............................................... 674 104
Changes in operating assets and liabilities:
Trade accounts receivable ........................ 13,587 (5,599)
Other receivables ................................ (6,822) (7,251)
Prepaid expenses ................................. (2,176) (1,107)
Other assets ..................................... (1,731) (682)
Accounts payable and accrued expenses ............ 52,391 2,658
Other liabilities ................................ (114) (2,065)
--------- ---------
Net cash provided by operating activities...... 253,671 124,887
--------- ---------
Cash flows used in investing activities:
Acquisition of business, net of cash acquired ............. (863) (2,166)
Property acquisitions ..................................... (187,137) (6,076)
Exploration and development expenditures .................. (189,278) (117,329)
Other property and equipment additions .................... (1,389) (444)
--------- ---------
Net cash used in investing activities ......... (378,667) (126,015)
--------- ---------
Cash flows provided by financing activities:
Repayments of long-term debt .............................. (53,080) (173)
Deferred financing costs .................................. (357) (725)
Equity offering costs ..................................... (87) --
Proceeds from long-term debt .............................. 128,000 (1,212)
Exercise of stock options and warrants .................... 7,994 3,094
--------- ---------
Net cash provided by financing activities ..... 82,470 984
--------- ---------
Net decrease in cash and cash equivalents ..... (42,526) (144)
Cash and cash equivalents at beginning of period ............. 93,537 104,392
--------- ---------
Cash and cash equivalents at end of period ................... $ 51,011 $ 104,248
========= =========
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, 2004 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, 2005 and for the three and
nine month periods ended September 30, 2005 and 2004 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, as amended, and the Amended and Restated 2000 Stock
Incentive 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 and earnings per share would
have been as shown in the pro forma amounts below:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2005 2004 2005 2004
------ ------ ------- -------
(IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Net income available to common stockholders:
As reported ..................................... $6,520 $8,746 $44,047 $29,098
Less: Pro forma net stock based employee
compensation cost, after tax ................. (485) (967) (655) (1,337)
------ ------ ------- -------
Pro forma ....................................... $6,035 $7,779 $43,392 $27,761
------ ------ ------- -------
Basic earnings per share:
As reported ..................................... $ 0.17 $ 0.27 $ 1.20 $ 0.89
Pro forma ....................................... $ 0.16 $ 0.24 $ 1.18 $ 0.85
Diluted earnings per share:
As reported ..................................... $ 0.16 $ 0.25 $ 1.11 $ 0.82
Pro forma ....................................... $ 0.15 $ 0.22 $ 1.09 $ 0.79
Stock-option based employee compensation cost,
net of tax, included in net income as reported .. $ -- $ -- $ 468 $ 340
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(3) ACQUISITIONS
In connection with the acquisition of a Company in 2002, the Company issued
among other things, $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, and $38.4 million of 11% Senior Subordinated
Notes (the Notes) due 2009 (immediately callable at par). On February 28, 2005,
the Company gave notice of the redemption of all of the Series D Preferred Stock
issued in connection with the acquisition that remained outstanding on the
redemption date of March 21, 2005. The redemption price was $100 per share plus
accrued and unpaid dividends to the redemption date. Holders of record had the
right to convert their shares into shares of common stock through the close of
business on March 18, 2005. All holders exercised their right to convert their
shares and there were no preferred shares outstanding as of the close of
business on March 18, 2005.
The Company also issued warrants to purchase four million shares of the
Company's common stock in the same business combination. Of the warrants, one
million had a strike price of $9.00 and three million had a strike price of
$11.00 per share. The warrants became exercisable on January 15, 2003 and expire
on January 15, 2007. At September 30, 2005 there were 755,341 warrants
outstanding with a strike price of $9.00 per share and 2,673,124 warrants
outstanding with a strike price of $11.00 per share.
In addition, former preferred stockholders of the acquired company 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 the acquired company as of the
closing date of the acquisition (the Ring-Fenced Properties) exceeds the net
present value discounted at 30%. The potential consideration is determined
annually from March 3, 2003 until March 1, 2007. The cumulative percentage
remitted to the participants was 20% for the March 3, 2003, 30% for the March 1,
2004 and 35% for the March 1, 2005 determination dates and is 40% for the March
1, 2006 and 50% for the March 1, 2007 determination dates. The contingent
consideration, if any, may be paid in the Company's common stock or cash at the
Company's option (with a minimum of 20% in cash) and in no event will exceed a
value of $50 million. In the first nine months of 2005 and 2004, the Company
capitalized, as additional purchase price, and paid additional consideration in
cash, of $0.9 million and $2.2 million related to the March 1, 2005 and the
March 1, 2004 contingent consideration determination dates, respectively. 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.
On January 20, 2005, the Company closed an acquisition of properties and
reserves in south Louisiana for approximately $148.1 million in cash, after
adjustments for the exercise of preferential rights by third parties and
preliminary closing adjustments. The entire purchase price was allocated to
property and equipment. The terms of the acquisition did not contain any
contingent consideration, options or future commitments. The acquisition was
composed of nine fields, four of which were producing at the time of the closing
through 14 wells, with estimated acquisition date proved reserves of 51.2
billion cubic feet equivalent. Also included were interests in 22 exploratory
prospects. The transaction expands the Company's exploration opportunities in
its expanded focus area and further reduces the concentration of its reserves
and production. Upon the signing of the purchase agreement, the Company paid a
$5.0 million deposit in 2004 toward the purchase price which was recorded as
other assets in the consolidated balance sheet at December 31, 2004. Concurrent
with the closing, the borrowing base under the Company's bank credit facility
was increased to $150 million, of which $60 million was drawn to fund the
acquisition. In connection with the acquisition, the Company has also entered
into a two-year agreement with the seller of the properties that defines an area
of mutual interest (AMI) encompassing over one million acres. The Company
intends to continue to explore and develop oil and natural gas reserves in the
AMI over that two year period jointly with the seller. The proved reserves,
prospects and AMI are in the southern portions of Terrebone, Lafourche and
Jefferson Parishes in Louisiana.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
The following unaudited pro forma information for the three and nine months
ended September 30, 2004 presents a summary of the consolidated results of
operations as if the acquisition occurred on January 1, 2004 with pro forma
adjustments to give effect to depreciation, depletion and amortization, interest
expense and related income tax effects.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
------------------ ------------------
(UNAUDITED, IN THOUSANDS, EXCEPT PER
SHARE AMOUNTS)
Pro forma:
Revenue .......................... $79,168 $227,808
Income from operations ........... 20,486 66,185
Net income ....................... 10,806 35,355
Basic income per common share .... $ 0.30 $ 1.00
Diluted income per common share .. $ 0.28 $ 0.92
On March 8, 2005, the Company closed the acquisition of the remaining 50%
gross working interest in South Timbalier 26 above approximately 13,000 feet
subsea that it did not already own for approximately $21.0 million after
preliminary closing adjustments from the effective date of December 1, 2004. The
entire purchase price was allocated to property and equipment. The terms of the
acquisition did not contain any contingent consideration, options or future
commitments. As a result of the acquisition, the Company now owns a 100% gross
working interest in the producing horizons in this field. The acquisition
expands the Company's interest in its core Greater Bay Marchand area and gives
the Company additional flexibility in undertaking the future development of the
South Timbalier 26 field.
The Company has included the results of operations from the acquisitions
discussed above from their respective closing dates. The Company has experienced
substantial revenue and production growth as a result of these acquisitions. For
the foregoing reasons these acquisitions will affect the comparability of the
Company's historical results of operations with future periods.
(4) EARNINGS PER SHARE
Basic earnings per share are computed by dividing income available to
common stockholders by the weighted average number of common shares outstanding
during the period. Diluted earnings per share is computed in the same manner as
basic earnings per share except that the denominator is increased to include the
number of additional common shares that could have been outstanding assuming the
conversion of convertible preferred stock shares, and the exercise of warrants
and stock options and the potential shares associated with restricted share
units that would have a dilutive effect on earnings per share.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(5) HEDGING ACTIVITIES
The Company enters into hedging transactions with major financial
institutions to reduce exposure to fluctuations in the price of oil and natural
gas. Any gains or losses resulting from the change in fair value from hedging
transactions that are determined to be ineffective are recorded in other
revenue, whereas gains and losses from the settlement of hedging contracts are
recorded in oil and natural gas revenue in the statements of operations. Crude
oil hedges are settled based on the average of the reported settlement prices
for West Texas Intermediate crude on the 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 may modify our collar to provide full upside participation after a
limited non-participation range.
The Company had the following hedging contracts as of September 30, 2005:
NATURAL GAS POSITIONS
-------------------------------------------------------------------------------------
VOLUME (MMBTU)
------------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/MMBTU) DAILY TOTAL
----------------------- ------------- ---------------------- ------ ---------
10/05 - 12/05.......... Collar $4.50/$10.75 20,000 1,840,000
10/05 - 12/05.......... Collar $5.00/$10.00 15,000 1,380,000
01/06 - 12/06.......... Collar $ 5.00/$9.51 15,000 5,475,000
01/07 - 12/07.......... Collar $ 5.00/$8.00 10,000 3,650,000
CRUDE OIL POSITIONS
-------------------------------------------------------------------------------------
VOLUME (BBLS)
------------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/BBL) DAILY TOTAL
----------------------- ------------- -------------------- ------ -------
10/05 - 12/05.......... Collar $31.00/$44.05 2,000 184,000
Settlements of hedging contracts reduced crude oil revenues by $3.5 million
and $6.2 million in the three and nine month periods ended September 30, 2005
and reduced natural gas revenues by $0.1 million in each of the three and nine
month periods ended September 30, 2005. The Company has not discontinued hedge
accounting treatment in the periods presented, and therefore, has not
reclassified gains or losses into earnings as a result.
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
The following tables reconcile the change in accumulated other
comprehensive income for the nine month periods ending September 30, 2005 and
2004.
NINE MONTHS ENDED
SEPTEMBER 30, 2005
-------------------
(IN THOUSANDS)
Accumulated other comprehensive loss as of December 31, 2004 $ (1,119)
Net income........................................................... $ 44,991
Other comprehensive loss - net of tax
Hedging activities
Reclassification adjustments for settled contracts - net of
taxes of $(2,278)........................................... 4,049
Changes in fair value of outstanding hedging positions - net of
taxes of $15,375............................................ (27,332)
--------
Total other comprehensive loss.............................. (23,283) (23,283)
-------- --------
Comprehensive income................................................. $ 21,708
========
Accumulated other comprehensive loss as of September 30, 2005........ $(24,402)
========
NINE MONTHS ENDED
SEPTEMBER 30, 2004
------------------
(IN THOUSANDS)
Accumulated other comprehensive loss as of December 31, 2003 ........ $(2,441)
Net income .......................................................... $31,671
Other comprehensive loss - net of tax
Hedging activities
Reclassification adjustments for settled contracts - net of
taxes of $(3,172) .......................................... 5,640
Changes in fair value of outstanding hedging positions - net of
taxes of $5,363 ............................................ (9,534)
-------
Total other comprehensive loss ............................. (3,894) (3,894)
------- -------
Comprehensive income................................................. $27,777
=======
Accumulated other comprehensive loss as of September 30, 2004 ....... $(6,335)
=======
Based upon current prices, the Company expects to transfer approximately
$26.5 million of pretax net deferred losses in accumulated other comprehensive
loss as of September 30, 2005 to earnings during the next twelve months when the
forecasted transactions actually occur.
(6) OIL AND GAS PROPERTIES
Effective July 1, 2005, the Company adopted Financial Accounting Standards
Board Staff Position FAS 19-1, "Accounting for Suspended Well Costs" (FSP 19-1).
FSP 19-1 amended Statement of Financial Accounting Standards No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies" (Statement 19), to
permit the continued capitalization of exploratory well costs beyond one year if
(a) the well found a sufficient quantity of reserves to justify its completion
as a producing well and (b) the entity is making sufficient progress assessing
the reserves and the economic and operating viability of the project. During the
quarter ended September 30, 2005, the Company adopted the requirements of FSP
19-1. During the Company's limited operating history it has not, and does not
currently, drill in areas that require major capital expenditures before
production can begin. Therefore,
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
upon adoption, the Company evaluated all existing capitalized well costs under
the provisions of FSP 19-1 and determined there was no impact to the Company's
consolidated financial statements.
(7) ASSET RETIREMENT OBLIGATION
Accounting and reporting standards require entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. The following table reconciles the beginning and
ending aggregate recorded amount of the asset retirement obligation for the nine
months ended September 30, 2005.
NINE MONTHS ENDED
SEPTEMBER 30, 2005
------------------
(IN THOUSANDS)
December 31, 2004......... $45,064
Accretion expense...... 3,054
Liabilities incurred... 6,029
Liabilities settled.... (54)
-------
September 30, 2005........ $54,093
=======
(8) COMMON STOCK
On July 16, 2004 the Company filed a universal shelf registration statement
(Shelf Registration Statement) which allowed the Company to issue an aggregate
of $300 million in common stock, preferred stock, senior debt and subordinated
debt in one or more separate offerings with the size, price and terms to be
determined at the time of the sale. On November 10, 2004 the Company sold
approximately 3.5 million shares of its common stock to the public pursuant to
this shelf registration statement. Concurrent with this offering, the Company
entered into a stock purchase agreement with Energy Income Fund, L.P. (EIF) in
which it purchased approximately 3.5 million shares of common stock owned by EIF
at a price per share equal to the net proceeds per share received in the
offering, before expenses. The Company therefore did not retain any of the
proceeds from this offering and the stock has been recorded as treasury stock on
the consolidated balance sheet at cost. The Company restored the Shelf
Registration Statement to $300 million in May 2005. The Company has no immediate
plans to enter into any additional transactions under this registration
statement, but plans to use the proceeds of any further offering under the Shelf
Registration Statement for general corporate purposes, which may include debt
repayment, acquisitions, expansion and working capital.
(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 (the 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 $145.3 million, which was used to redeem all of the
outstanding 11% Senior Subordinated Notes Due 2009, that had been issued in
connection with a business combination in 2002, and to repay substantially all
of the borrowings outstanding under the Company's bank credit facility. In
January 2005 the remainder of the net proceeds were used to purchase properties
in south Louisiana as discussed in note (3).
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
The Registered 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 Registered 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 Registered Senior Notes are not subject to any sinking fund
requirements.
On August 3, 2004, the Company amended and extended to August 3, 2008 its
bank credit facility. The borrowing base was increased to $150 million at the
time of the Company's purchase of south Louisiana properties and reserves in
January 2005. At September 30, 2005 the Company had $75.0 million outstanding
under the bank credit facility. The borrowing base remains subject to
redetermination based on the proved reserves of the oil and natural gas
properties that serve as collateral for the bank credit facility as set out in
the reserve report delivered to the banks each April 1 and October 1. The
Company's borrowing base was reaffirmed effective November 1, 2005.
(10) TROPICAL WEATHER
On August 29, 2005 Hurricane Katrina made landfall in the United States
south of New Orleans causing catastrophic damage throughout portions of the Gulf
of Mexico and to portions of Alabama, Louisiana and Mississippi, including New
Orleans. As a result of the devastating effects of the storm on New Orleans and
surrounding areas, the Company announced on August 30 that it had elected to
establish temporary headquarters at its Houston, Texas office. A satellite
office was also established in Baton Rouge, Louisiana. General and
administrative costs associated with moving offices as well as relocation
allowances paid to employees approximated $1.0 million during the quarter and
are recorded in other general and administrative expenses in the consolidated
statement of operations.
On September 24, 2005 Hurricane Rita made landfall in the United States on
the Texas/Louisiana border. This hurricane caused extensive damage throughout
portions of the Gulf of Mexico region particularly to third party infrastructure
such as pipelines and processing plants.
As a result of these two major hurricanes and two other hurricanes and a
tropical storm that traversed the Gulf of Mexico and adjacent land areas in July
2005, nearly all of the Company's production was shut in at one time or another
during the quarter and a significant portion of that production had not yet been
restored as of the date of the filing of this Form 10-Q. The Company is
continuing to work to bring production back to pre-storm levels, but is subject
to constraints due to damage to third party infrastructure. The Company
maintains business interruption insurance on its significant properties,
including its East Bay field. Recovery of lost revenue for the East Bay field
and the South Timbalier 26 field began accruing in October and recovery on the
South Marsh Island 109 field is currently expected to begin accruing in
November. Recovery will continue, including situations where production is
shut-in due to third party constraints, until production is restored to
pre-storm levels, subject to policy limits that the Company does not expect at
this time to be reached. Total offshore repair costs expended as of
September 30, 2005 for Hurricanes Katrina and Rita and Tropical Storm Cindy
were $7.5 million. Of this amount $2.2 million represents uninsured amounts
that are reflected in lease operating expenses and the remaining $5.3 million
is recorded in other receivables on the Company's consolidated balance sheet.
(11) NEW ACCOUNTING PRONOUNCEMENTS
In November 2004, the FASB issued Statement of Financial Accounting
Standards No. 151 "Inventory Costs, an amendment of ARB No. 43, Chapter 4"
(Statement 151). The amendments made by Statement 151 clarify that abnormal
amounts of idle facility expense, freight, handling costs, and wasted materials
(spoilage) should be recognized as current-period charges and require the
allocation of fixed production overheads to inventory based on the normal
capacity of the production facilities. The guidance is effective for inventory
costs incurred during fiscal years beginning after June 15, 2005. Earlier
application is permitted for inventory costs incurred during fiscal years
beginning after November 23, 2004. The Company's assessment of the provisions of
Statement 151 is that it does not have an impact on the financial position,
results of operations or cash flows of the Company.
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 153 "Exchanges of Non-monetary assets - an amendment of APB
Opinion No. 29" (Statement 153). Statement 153 amends Accounting Principles
Board (APB) Opinion 29 to eliminate the exception for nonmonetary exchanges of
similar productive assets and replaces it with a general exception for exchanges
of nonmonetary assets that do not have commercial substance. A nonmonetary
exchange has commercial substance if the future cash flows of the entity are
expected to change significantly as a result of the exchange. Statement 153 does
not apply to a pooling of assets in a joint undertaking intended to fund,
develop, or produce oil or natural gas from a particular property or group of
properties. The provisions of Statement 153 shall be effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early
adoption is permitted and the provisions of Statement 153 should be applied
prospectively. The Company's assessment of the provisions of Statement 153 is
that it is not expected to have an impact on the financial position, results of
operations or cash flows of the Company.
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 123-Revised 2004, "Share-Based Payment," (Statement 123R). This is
a revision of Statement of Financial Accounting Standards No. 123, "Accounting
for Stock-Based Compensation", and supersedes APB No. 25, "Accounting for Stock
Issued to Employees." The Company currently accounts for stock-based
compensation under the provisions of APB No. 25. Under Statement 123R, the
Company will be required to measure the cost of employee services received in
exchange for stock based on the grant-date fair value (with limited exceptions).
That cost will be recognized as expense over the period during which an employee
is required to provide service in exchange for the award (usually the vesting
period). The fair value will be estimated using an option-pricing model. Excess
tax benefits, as defined in Statement 123R, will be recognized as an addition to
paid-in capital. This will be effective for the Company as of the beginning of
the first annual reporting period that begins after June 15, 2005. The Company
is currently in the process of evaluating the impact of Statement 123R on its
financial statements, including different option-pricing models. Note (2)
illustrates the current effect on net income and earnings per share if the
Company had applied the fair value recognition provisions of Statement 123.
In May 2005, the FASB issued Statement of Financial Accounting Standards
No. 154, "Accounting Changes and Error Corrections--a replacement of APB Opinion
No. 20 and FASB Statement No. 3," (Statement 154). Statement 154 provides
guidance on the accounting for and reporting of accounting changes and error
corrections. It establishes, unless impracticable, retrospective application as
the required method for reporting a change in accounting principle in the
absence of explicit transition requirements specific to Statement 154. The
provisions of Statement 154 shall be effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
(12) 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.
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
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.
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET
AS OF SEPTEMBER 30, 2005
PARENT
COMPANY GUARANTOR
ONLY SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------
(IN THOUSANDS)
ASSETS
Current assets:
Cash and cash equivalents ............... $ 51,011 $ -- $ -- $ 51,011
Accounts receivable ..................... 222,489 (164,313) -- 58,176
Other current assets .................... 14,708 59 -- 14,767
--------- --------- --------- ----------
Total current assets ................. 288,208 (164,254) -- 123,954
Property and equipment ..................... 748,080 407,646 -- 1,155,726
Less accumulated depreciation, depletion
and amortization ...................... (282,644) (107,190) -- (389,834)
--------- --------- --------- ----------
Net property and equipment ........... 465,436 300,456 -- 765,892
Investment in affiliates ................... 96,995 -- (96,995) --
Notes receivable, long-term ................ -- 70,363 (70,363) --
Other assets ............................... 21,223 (21) -- 21,202
--------- --------- --------- ----------
$ 871,862 $ 206,544 $(167,358) $ 911,048
========= ========= ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses ... $ 164,490 $ 925 $ -- $ 165,415
Fair value of commodity derivative
instruments .......................... 26,502 -- -- 26,502
Current maturities of long-term debt .... -- 137 -- 137
--------- --------- --------- ----------
Total current liabilities ............ 190,992 1,062 -- 192,054
Long-term debt ............................. 225,000 70,363 (70,363) 225,000
Other liabilities .......................... 102,737 38,124 -- 140,861
--------- --------- --------- ----------
518,729 109,549 (70,363) 557,915
Stockholders' equity:
Common stock ............................ 415 -- -- 415
Additional paid-in capital .............. 347,289 -- -- 347,289
Accumulated other comprehensive loss .... (24,402) -- -- (24,402)
Retained earnings ....................... 87,263 96,995 (96,995) 87,263
Treasury stock .......................... (57,432) -- -- (57,432)
--------- --------- --------- ----------
Total stockholders' equity ........... 353,133 96,995 (96,995) 353,133
--------- --------- --------- ----------
$ 871,862 $ 206,544 $(167,358) $ 911,048
========= ========= ========= ==========
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2005
PARENT
COMPANY GUARANTOR
ONLY SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------
(IN THOUSANDS)
Revenue:
Oil and natural gas ......................... $208,198 $87,462 $ -- $295,660
Other ....................................... 23,818 286 (24,081) 23
-------- ------- -------- --------
232,016 87,748 (24,081) 295,683
Costs and expenses:
Lease operating expenses .................... 32,110 9,403 -- 41,513
Taxes, other than on earnings ............... 1,598 6,660 -- 8,258
Exploration expenditures .................... 34,710 18,230 -- 52,940
Depreciation, depletion and amortization .... 51,084 28,346 -- 79,430
General and administrative .................. 29,266 12,267 (11,250) 30,283
-------- ------- -------- --------
Total costs and expenses ................. 148,768 74,906 (11,250) 212,424
Income from operations ......................... 83,248 12,842 (12,831) 83,259
Interest expense, net .......................... (12,783) (11) -- (12,794)
-------- ------- -------- --------
Income before income taxes ..................... 70,465 12,831 (12,831) 70,465
Income taxes ................................... (25,474) -- -- (25,474)
-------- ------- -------- --------
Net income ..................................... $ 44,991 $12,831 $(12,831) $ 44,991
======== ======= ======== ========
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2005
PARENT
COMPANY GUARANTOR
ONLY SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------
(IN THOUSANDS)
Net cash provided by operating activities ......... $ 25,947 $ 227,724 $ -- $ 253,671
Cash flows used in investing activities:
Acquisition of business, net of cash
acquired .................................... (863) -- -- (863)
Property acquisitions .......................... (45,300) (141,837) -- (187,137)
Exploration and development expenditures ....... (103,471) (85,807) -- (189,278)
Other property and equipment additions ......... (1,389) -- -- (1,389)
--------- --------- ------- ---------
Net cash used in investing activities ............. (151,023) (227,644) -- (378,667)
--------- --------- ------- ---------
Cash flows provided by financing activities:
Deferred financing costs ....................... (357) -- -- (357)
Repayments of long-term debt ................... (53,000) (80) -- (53,080)
Equity offering costs .......................... (87) -- -- (87)
Proceeds from long-term debt ................... 128,000 -- -- 128,000
Exercise of stock options and warrants ......... 7,994 -- -- 7,994
--------- --------- ------- ---------
Net cash provided by financing activities ......... 82,550 (80) -- 82,470
--------- --------- ------- ---------
Net decrease in cash and cash equivalents ......... (42,526) -- -- (42,526)
Cash and cash equivalents at beginning of period .. 93,537 -- -- 93,537
--------- --------- ------- ---------
Cash and cash equivalents at end of period ........ $ 51,011 $ -- $ -- $ 51,011
========= ========= ======= =========
(13) 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.
(14) RECLASSIFICATIONS
Certain reclassifications have been made to the prior period financial
statements in order to conform to the classification adopted for reporting in
fiscal 2005.
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
We were incorporated in January 1998 and operate in a single segment as an
independent oil and natural gas exploration and production company. Our current
operations are concentrated in the shallow to moderate depth waters of the Gulf
of Mexico Shelf and the Gulf Coast onshore region.
While the impacts of Hurricane Katrina and Rita were significant, during
the first nine months of 2005 we still made progress toward implementing our
long-term growth strategy. Our strong cash flow provided us the flexibility to
make necessary and appropriate investments to continue our strategy. Our
long-term strategy is to increase our oil and natural gas reserves and
production while keeping our finding and development costs and operating costs
competitive with our industry peers. We will implement this strategy through
drilling exploratory wells from our inventory of available prospects that we
have evaluated for geologic and mechanical risk and future reserve or resource
potential, through drilling development wells and working over and recompleting
existing wells, entering into farmout agreements and by making acquisitions. Our
drilling program contains some higher risk, higher reserve potential
opportunities as well as some lower risk, lower reserve potential opportunities,
in order to achieve a balanced program of reserve and production growth.
We use the successful efforts method of accounting for our investment in
oil and natural gas properties. Under this method, we capitalize lease
acquisition costs, costs to drill and complete exploration wells in which proven
reserves are discovered and costs to drill and complete development wells.
Exploratory drilling costs are charged to expense if and when the well is
determined not to have found reserves in commercial quantities. Seismic,
geological and geophysical and delay rental expenditures are expensed as they
are 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, 2004, includes
a discussion of our critical accounting policies, which have not changed
significantly since the end of the fiscal year.
On August 5, 2003, we issued $150 million of 8.75% Senior Notes Due 2010 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 8.75%
Senior Notes Due 2010 having substantially identical terms for the privately
placed 8.75% Senior Notes due 2010. After discounts and commissions and
estimated offering expenses, we received $145.3 million, which was used to (i)
redeem all of our outstanding 11% Senior Subordinated Notes Due 2009 (the
"Notes"), which had been issued in connection with a business combination in
2002, and (ii) repay substantially all of the borrowings outstanding under our
bank credit facility. In January 2005 the remainder of the net proceeds were
used to purchase properties in south Louisiana.
On July 16, 2004, we filed a universal shelf registration statement (the
"Registration Statement") which allowed us to issue an aggregate of $300 million
in common stock, preferred stock, senior debt and subordinated debt in one or
more separate offerings with the size, price and terms to be determined at the
time of the sale. On November 10, 2004 we sold approximately 3.5 million shares
of our common stock to the public pursuant to the Registration Statement.
Concurrent with this offering, we entered into a stock purchase agreement with
Energy Income Fund, L.P. ("EIF") pursuant to which we purchased an equal number
of shares of common stock owned by EIF at a price per share equal to the
proceeds per share received in the offering, before expenses. We did not retain
any of the proceeds from the offering and the shares are now held as treasury
shares, at cost. We restored the Registration Statement to $300 million in May
2005. We have no immediate plans to enter into any additional transactions under
the Registration Statement, but plan to use the proceeds of any future offering
under the Registration Statement for general corporate purposes, which may
include debt repayment, acquisitions, expansion and working capital.
17
On August 3, 2004, we amended and extended to August 3, 2008 our bank
credit facility. The borrowing base was increased to $150 million at the time of
our purchase of south Louisiana properties and reserves in January 2005. At
September 30, 2005 the Company had $75.0 million outstanding under the bank
credit facility. The borrowing base remains subject to redetermination based on
the proved reserves of the oil and natural gas properties that serve as
collateral for the bank credit facility. The Company's borrowing base was
reaffirmed effective November 1, 2005.
On January 20, 2005, we closed an acquisition of properties and reserves in
south Louisiana for $148.1 million in cash, after adjustments for the exercise
of preferential rights by third parties and preliminary closing adjustments. The
acquisition was composed of nine fields, four of which were producing at the
time of the closing through 14 wells, with estimated acquisition date proved
reserves of 51.2 billion cubic feet equivalent. Also included were interests in
22 exploratory prospects. The transaction expanded the exploration opportunities
in our expanded focus area and further reduced the concentration of our reserves
and production. Upon the signing of the purchase agreement, we paid a $5.0
million deposit in 2004 toward the purchase price which was recorded as other
assets in the consolidated balance sheet, and concurrent with the closing, the
borrowing base under our bank credit facility was increased to $150 million, of
which $60 million was drawn to fund the acquisition. In connection with the
acquisition, we also entered into a two-year agreement with the seller of the
properties that defined an area of mutual interest ("AMI") encompassing over one
million acres. We intend to continue to explore and develop oil and natural gas
reserves in the AMI over the two year term jointly with the seller. The proved
reserves, prospects and the AMI are in the southern portions of Terrebone,
Lafourche and Jefferson Parishes in Louisiana.
On March 8, 2005, we closed the acquisition of the remaining 50% gross
working interest in South Timbalier 26 above approximately 13,000 feet subsea
that we did not already own for approximately $21.0 million after preliminary
closing adjustments from the effective date of December 1, 2004. As a result of
the acquisition, we now own a 100% gross working interest in the producing
horizons in this field. The acquisition expands our interest in our core Greater
Bay Marchand area and gives us additional flexibility in undertaking the future
development of the South Timbalier 26 field.
We have included the results of operations from the acquisitions discussed
above from their respective closing dates. We had experienced substantial
revenue and production growth as a result of these acquisitions though the
period prior to the tropical weather discussed below. For the foregoing reasons
these acquisitions will affect the comparability of our historical results of
operations with future periods.
On August 29, 2005 Hurricane Katrina made landfall in the United States
south of New Orleans causing catastrophic damage throughout portions the Gulf of
Mexico and to portions of Alabama, Louisiana and Mississippi, including New
Orleans. As a result of the devastating effects of the storm on New Orleans and
surrounding areas, we announced on August 30 that we had elected to establish
temporary headquarters at our Houston, Texas office. A satellite office was also
established in Baton Rouge, Louisiana.
On September 24, 2005 Hurricane Rita made landfall in the United States on
the Texas/Louisiana border between Sabine Pass, Texas and Johnson's Bayou,
Louisiana. This hurricane caused extensive damage throughout portions of the
region particularly to third party infrastructure such as pipelines and
processing plants.
As a result of these two major hurricanes and two other hurricanes and a
tropical storm that traversed the Gulf of Mexico and adjacent land areas in July
2005, nearly all of our production was shut in at one time or another during the
quarter and a significant portion of that production had not yet been restored
as of the date of the filing of this Form 10-Q. We are continuing to work to
bring production back to pre-storm levels, but are subject to constraints due to
damage to third party infrastructure. We maintain business interruption
insurance on our significant properties, including our East Bay field. Recovery
of lost revenue for our East Bay field and our South Timbalier 26 field began
accruing in October and recovery on our South Marsh Island 109 field is
currently expected to begin accruing in November. This recovery will continue
until production is restored to pre-storm levels, subject to policy limits that
we do not expect at this time to be reached.
18
Our revenue, profitability and future growth rate depend substantially on
factors beyond our control, such as economic, political and regulatory
developments, tropical weather 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.
We currently have an extensive inventory of drillable prospects in-house,
we are generating more prospects internally and we are exploring new
opportunities through relationships with industry partners. Despite our expanded
budget in 2005, strong commodity prices applied to our produced volumes, even
after taking into account the effect of recent tropical storms on those volumes,
should enable us to adhere to our policy of funding our exploration and
development expenditures with internally generated cash flow. This strategy
allows us to preserve our strong balance sheet to finance acquisitions and other
capital intensive projects that might result from exploration and development
activities. In addition to the south Louisiana and South Timbalier 26 property
acquisitions already completed earlier this year, we believe the near term may
provide us with opportunities to acquire targeted properties, including those
within our focus area.
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,
------------------ -------------------
2005 2004 2005 2004
-------- ------- -------- --------
Net production (per day):
Oil (Bbls) ............................................. 6,642 8,893 9,017 8,433
Natural gas (Mcf) ...................................... 75,899 86,050 90,596 83,422
Total barrels of oil equivalent (Boe) ............... 19,292 23,235 24,116 22,337
Oil and natural gas revenues (in thousands):
Oil .................................................... $ 30,279 $28,154 $114,935 $ 76,737
Natural gas ............................................ 61,698 45,843 180,725 135,656
Total ............................................... 91,977 73,997 295,660 212,393
Average sales prices, net of hedging:
Oil (per Bbl) .......................................... $ 49.55 $ 34.41 $ 46.69 $ 33.21
Natural gas (per Mcf) .................................. 8.84 5.79 7.31 5.93
Total (per Boe) ..................................... 51.82 34.62 44.91 34.70
Impact of hedging:
Oil (per Bbl) .......................................... $ (5.76) $ (5.39) $ (2.53) $ (3.55)
Natural gas (per Mcf) .................................. (0.01) -- -- (0.03)
Average costs (per Boe):
Lease operating expense ................................ $ 7.98 $ 4.94 $ 6.19 $ 4.89
Taxes, other than on earnings .......................... 1.60 1.00 1.25 1.05
Depreciation, depletion and amortization ............... 14.81 11.84 12.06 10.83
Increase in oil and natural gas revenues between periods
presented (in thousands, net of hedging) due to:
Changes in prices of oil ............................... $ 12,384 $ 30,754
Changes in production volumes of oil ................... (10,259) 7,444
Total increase in oil sales ......................... 2,125 38,198
Changes in prices of natural gas ....................... $ 24,092 $ 30,810
Changes in production volumes of natural gas ........... (8,237) 14,259
Total increase in natural gas sales ................. 15,855 45,069
19
REVENUES AND NET INCOME
Our oil and natural gas revenues increased to $92.0 million in the third
quarter of 2005 from $74.0 million in the third quarter of 2004. Our oil and
natural gas revenues increased to $295.7 million in the first nine months of
2005 from $212.4 million in the first nine months of 2004. The increase for
these periods is the result of sharply increased oil and natural gas prices
which were driven even higher during the quarter by Hurricanes Katrina and Rita.
The year to date period had increased production from 2 new oil and 21 new
natural gas wells brought on production since the end of the third quarter of
2004. In addition, the acquisitions, in the first quarter of 2005, of the south
Louisiana properties and the additional interest in South Timbalier 26 added
incremental production to the year. However, these increases were adversely
impacted by an estimated 8,830 Boe per day of deferred production for the third
quarter of 2005 and 2,976 Boe per day of deferred production for the nine months
ended September 30, 2005 from production shut-ins resulting from Hurricanes
Katrina, Rita, Dennis and Emily and Tropical Storm Cindy (the "Tropical
Weather") compared to deferred production of 1,500 Boe per day in the third
quarter of 2004 and 504 Boe per day for the nine months ended September 30, 2004
from Hurricane Ivan-related shut-ins.
We recognized net income of $6.5 million in the third quarter of 2005
compared to net income of $9.6 million in the third quarter of 2004. The
decrease was due to the effects of the Tropical Weather which significantly
decreased production for the quarter despite the sharp increase in prices as
discussed above and increases in our operating expenses as discussed below.
We recognized net income of $45.0 million in the first nine months of 2005
compared to net income of $31.7 million in the first nine months of 2004. The
increase was primarily a result of the increase in oil and natural gas revenues
through the first nine months significantly offset by the effects of the
Tropical Weather on our production and increased costs in the third quarter
discussed below.
These results were strong as compared to 2004; however we did not achieve
the sequential growth in volumes that we anticipated from the second quarter of
2005 due to downtime from the Tropical Weather during the quarter resulting in
shut-in or reduced production affecting nearly all of our producing fields
during the quarter.
OPERATING EXPENSES
Operating expenses during the three and nine month periods ended September
30, 2005 and 2004 were affected by the following:
- Lease operating expense increased in the third quarter of 2005 to
$14.2 million compared to $10.6 million in the third quarter of 2004.
Lease operating expense increased to $40.7 million in the first nine
months of 2005 from $29.9 million in the first nine months of 2004.
This increase in both periods is primarily a result of the uninsured
portion of repairs due to the Tropical Weather of $2.2 million, but
was also affected by new wells coming on stream in new fields,
acquisitions during the first quarter of 2005, workovers in the
current periods as well as a general increase in the cost of oilfield
industry services.
- Taxes, other than on earnings, increased slightly to $2.8 million in
the third quarter of 2005 from $2.1 million in the third quarter of
2004. Taxes, other than on earnings, increased to $8.3 million in the
first nine months of 2005 from $6.4 million in the first nine months
of 2004. The increase was due to the increase in commodity prices and
production from non-federal leases as a result of the south Louisiana
property acquisition. These taxes are expected to fluctuate from
period to period depending on our production volumes from non-federal
leases and the commodity prices received.
- Exploration expenditures, including dry hole costs, increased to $23.3
million in the third quarter of 2005 from $10.0 million in the third
quarter of 2004. The expense in the third quarter of 2005 is comprised
of $10.6 million of costs for exploratory wells or portions thereof
which were found to be not commercially productive and $9.3 million of
proved property impairments at three of our fields which would need
significant capital to extend their economic lives. We have decided
that the capital will be deployed to projects with more potential and
have therefore impaired the assets. In addition, there was $3.4
million of seismic expenditures and delay rentals. The expense in the
third quarter of 2004 is comprised of $7.4 million of costs for
exploratory wells or portions thereof which
20
were found to be not commercially productive and $2.6 million for
seismic expenditures and delay rentals.
Exploration expenditures, including dry hole costs, increased to $52.9
million in the first nine months of 2005 from $26.9 million in the
first nine months of 2004. The expense in the first nine months of
2005 is comprised of $31.2 million of costs for exploratory wells or
portions thereof which were found to be not commercially productive,
$9.3 million of proved property impairments at three of our fields
discussed above, $0.7 million of proved property impairments in the
second quarter, as well as $11.7 million of seismic expenditures and
delay rentals, whereas the expense in the first nine months of 2004 is
comprised of $13.8 million of costs for exploratory wells or portions
thereof which were found to be not commercially productive, $6.9
million of proved property impairments at our East Cameron 378 field
and $6.2 million of seismic expenditures and delay rentals.
Our exploration expenditures, including dry hole charges, will vary
depending on the amount of our capital budget dedicated to exploration
activities and the level of success we achieve in exploratory drilling
activities.
- Depreciation, depletion and amortization increased to $26.3 million in
the third quarter of 2005 from $25.3 million in the third quarter of
2004. Depreciation, depletion and amortization increased to $79.4
million in the first nine months of 2005 from $66.3 million in the
first nine months of 2004. The increase was a result of higher
production in the year to date period despite deferred production
during the third quarter from the Tropical Weather. The higher expense
in the third quarter of this year is a result of production shut-ins
resulting from the Tropical Weather occurring at our lower rate
fields.
However, in both periods, the shift in the production contribution
amongst our various fields increased our expense per Boe. Some fields
carry a higher depreciation burden than others; therefore, changes in
the sources of our production will directly impact this expense.
- Other general and administrative expenses increased to $7.8 million in
the third quarter of 2005 from $6.7 million in the third quarter of
2004. Other general and administrative expenses increased to $24.1
million in the first nine months of 2005 from $20.4 million in the
first nine months of 2004. The increase was primarily due to costs
associated with temporarily relocating our personnel and headquarters
to Houston and opening a Baton Rouge office in the wake of Hurricane
Katrina. Costs incurred of approximately $1.0 million included
employee relocation allowances and housing, temporary office space and
furniture rental as well as the purchase of computer equipment. At
this time we anticipate that the expense for these items will
approximate $0.7 million in the fourth quarter of 2005. In addition,
the change was due to increased personnel costs resulting from our
overall increased level of activity and expanded asset base.
- Non-cash stock-based compensation expense of $2.5 million was
recognized in the third quarter of 2005 compared to $1.0 million in
the third quarter of 2004. Non-cash stock-based compensation expense
of $6.2 million was recognized in the first nine months of 2005
compared to $2.6 million in the first nine months of 2004. The
increased expense relates to the increased amortization of new
restricted stock and performance share awards made to employees in
late 2004 and in 2005 as well as the impact of the increased stock
price on our variable awards and accelerated vesting of stock awards
for two former employees.
OTHER INCOME AND EXPENSE
Interest expense increased to $4.9 million in the third quarter of 2005
from $3.6 million in the third quarter of 2004. Interest expense increased to
$13.3 million in the first nine months of 2005 from $10.8 million in the first
nine months of 2004. The increase was a result of interest expense on borrowings
under our bank credit facility to finance acquisitions.
21
LIQUIDITY AND CAPITAL RESOURCES
The trend of increased revenues we have experienced from 2004 into the
first nine months of 2005 has continued to provide strong cash flows from
operations which totaled $253.7 million in the first nine months of the year. We
intend to fund our exploration and development expenditures from internally
generated cash flows, which we define as cash flows from operations before
changes in working capital plus total exploration expenditures. Our cash on hand
at September 30, 2005 was $51.0 million. Our future internally generated cash
flows will depend on our ability to maintain and increase production through our
development and exploratory drilling program, as well as the prices we receive
for oil and natural gas. We may, from time to time, use our bank credit facility
to fund working capital needs.
Our bank credit facility, as amended on August 3, 2004, consists of a
revolving line of credit with a group of banks available through August 3, 2008
(the "bank credit facility"). The bank credit facility currently has a borrowing
base of $150 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. The bank credit facility permits both prime rate
borrowings and London interbank offered rate ("LIBOR") borrowings plus a
floating spread. The spread will float up or down based on our utilization of
the bank credit facility. The spread can range from 1.25% to 2.00% above LIBOR
and 0% to 0.75% above prime. The borrowing base under the bank credit facility
is secured by substantially all of our assets. We used our bank credit facility
to fund a portion of the purchase of the south Louisiana properties in January
2005 and the acquisition of the additional interest in South Timbalier 26 in
March 2005. At November 4, 2005 we had $75.0 million outstanding and $75.0
million of credit capacity available under the bank credit facility. In
addition, we pay an annual fee on the unused portion of the bank credit facility
ranging between 0.375% to 0.5% based on utilization. The bank credit facility
contains customary events of default and various financial covenants, which
require us to: (i) maintain a minimum current ratio, as defined in our bank
credit facility agreement, of 1.0 and (ii) maintain a minimum EBITDAX to
interest ratio, as defined in our bank credit facility agreement, of 3.5. We
were in compliance with the bank credit facility covenants as of September 30,
2005.
On August 5, 2003, we issued $150 million of our 8.75% senior notes due
2010 which were exchanged in October 2003 for registered 8.75% senior notes due
2010 (the "Senior Notes") with substantially the same terms. 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 Senior
Notes at our option, in whole or in part, at any time on or after August 1, 2007
at a price equal to 100% of the principal amount plus accrued and unpaid
interest, if any, plus a specified premium which decreases yearly from 4.375% in
2007 to 0% in 2009 and thereafter. In addition, at any time prior to August 1,
2006, we may redeem up to a maximum of 35% of the aggregate principal amount
with the net proceeds of certain equity offerings at a price equal to 108.75% of
the principal amount, plus accrued and unpaid interest. The notes are unsecured
obligations and rank equal in right of payment to all existing and future senior
debt, including the bank credit facility, and will rank senior or equal in right
of payment to all existing and future subordinated indebtedness. The indenture
relating to the Senior Notes contains certain restrictions on our ability to
incur additional debt, pay dividends on our common stock, make investments,
create liens on our assets, engage in transactions with our affiliates, transfer
or sell assets and consolidate or merge substantially all of our assets. The
Senior Notes are not subject to any sinking fund requirements.
Net cash of $378.7 million used in investing activities in the first nine
months of 2005 consisted primarily of the acquisition of south Louisiana
properties and of an additional interest in South Timbalier 26, as well as oil
and natural gas exploration and development 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 2005, we
completed 51 drilling projects, 33 of which were successful, and 25
recompletion/workover projects, 20 of which were successful. During the first
nine months of 2004, we completed 21 drilling projects, 15 of which were
successful, and 17 recompletion/workover projects, 13 of which were successful.
22
Our 2005 capital exploration and development 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 and our proved properties, and does not include acquisitions.
We continue to manage our portfolio in order to maintain an appropriate risk
balance between low risk development and exploitation activities, moderate risk
exploration opportunities and higher risk, higher potential exploration
opportunities. Our exploration and development budget for 2005 is currently
approximately $307 million inclusive of expected incremental drilling
expenditures on properties acquired through acquisitions closed thus far during
the year. We do not budget for acquisitions. During the first nine months of
2005, capital and exploration expenditures were approximately $421.5 million
inclusive of a $0.9 million contingent consideration payment resulting from an
acquisition during 2002 and $192.1 million related to the acquisition of leases
and producing assets in 2005. The level of our capital and exploration
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 and availability of drilling rigs and
other oilfield goods and services. Should actual conditions differ materially
from expectations, some projects may be accelerated or deferred and,
consequently, may increase or decrease total 2005 capital expenditures.
We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active capital expenditure
program. We believe that internally generated cash flows will be sufficient to
meet our budgeted capital requirements for at least the next twelve months.
Availability under the bank credit facility may 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, 2004
included a discussion of our contractual obligations. There have been no
material changes to that disclosure during the nine months ended September 30,
2005. In addition, we do not maintain any off balance sheet transactions,
arrangements, obligations or other relationships with unconsolidated entities or
others that are reasonably likely to have a material current or future effect on
our financial condition, changes in financial condition, revenues and expenses,
results of operations, liquidity, capital expenditures or capital resources.
NEW ACCOUNTING PRONOUNCEMENTS
In November 2004, the FASB issued Statement of Financial Accounting
Standards No. 151 "Inventory Costs, an amendment of ARB No. 43, Chapter 4"
("Statement 151"). The amendments made by Statement 151 clarify that abnormal
amounts of idle facility expense, freight, handling costs, and wasted materials
(spoilage) should be recognized as current-period charges and require the
allocation of fixed production overheads to inventory based on the normal
capacity of the production facilities. The guidance is effective for inventory
costs incurred during fiscal years beginning after June 15, 2005. Earlier
application is permitted for inventory costs incurred during fiscal years
beginning after November 23, 2004. Our assessment of the provisions of Statement
151 is that it does not have an impact on our financial position,
results of operations or cash flows.
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 153 "Exchanges of Non-monetary assets - an amendment of APB
Opinion No. 29" ("Statement 153"). Statement 153 amends Accounting Principles
Board ("APB") Opinion 29 to eliminate the exception for nonmonetary exchanges of
similar productive assets and replaces it with a general exception for exchanges
of nonmonetary assets that do not have commercial substance. A nonmonetary
exchange has commercial substance if the future cash flows of the entity are
expected to change significantly as a result of the exchange. Statement 153 does
not apply to a pooling of assets in a joint undertaking intended to fund,
develop, or produce oil or natural gas from a particular property or group of
properties. The provisions of Statement 153 shall be effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early
adoption is permitted and the provisions of Statement 153 should be applied
prospectively. Our assessment of the provisions of Statement 153 is that it is
not expected to have an impact on our financial position, results of operations
or cash flows.
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 123-Revised 2004, "Share-Based Payment," ("Statement 123R"). This
is a revision of Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation", and supersedes APB No. 25,
"Accounting for Stock Issued to Employees." We currently account for stock-based
compensation under the provisions of APB 25. Under Statement 123R, we will be
required to measure the cost of
23
employee services received in exchange for stock, based on the grant-date fair
value (with limited exceptions). That cost will be recognized as expense over
the period during which an employee is required to provide service in exchange
for the award (usually the vesting period). The fair value will be estimated
using an option-pricing model. Excess tax benefits, as defined in Statement
123R, will be recognized as an addition to paid-in capital. This will be
effective for us as of the beginning of the first annual reporting period that
begins after June 15, 2005. We are currently in the process of evaluating the
impact of Statement 123R on our financial statements, including different
option-pricing models. Note (2) of the Notes to Consolidated Financial
Statements illustrates the current effect on net income and earnings per share
if we had applied the fair value recognition provisions of Statement 123.
In May 2005, the FASB issued Statement of Financial Accounting Standards
No. 154, "Accounting Changes and Error Corrections--a replacement of APB Opinion
No. 20 and FASB Statement No. 3," (Statement 154). Statement 154 provides
guidance on the accounting for and reporting of accounting changes and error
corrections. It establishes, unless impracticable, retrospective application as
the required method for reporting a change in accounting principle in the
absence of explicit transition requirements specific to Statement 154. The
provisions of Statement 154 shall be effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
FORWARD LOOKING INFORMATION
All statements other than statements of historical fact contained in this
Report on Form 10-Q ("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, 2004. 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 our bank credit facility. Currently, we do not use
interest rate derivative instruments to manage exposure to interest rate
changes. At September 30, 2005, $75.0 million of our long-term debt had variable
interest rates while the remaining long-term debt had fixed interest expense. If
the market interest rates had averaged 1% higher in the third quarter of 2005,
interest rates for the period on variable rate debt outstanding during the
period would have increased, and net income before income taxes would have
decreased by approximately $0.2 million based on total variable debt outstanding
during the period. If market interest rates had averaged 1% lower in the third
quarter of 2005, interest expense for the period on variable rate debt would
have decreased, and net income before income taxes would have increased by
approximately $0.2 million.
24
COMMODITY PRICE RISK
Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and natural gas. Prices also affect the amount of cash
flow available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under our bank credit facility is
subject to periodic redetermination based in part on changing expectations of
future prices. Lower prices may also reduce the amount of oil and natural gas
that we can economically produce. We currently sell all of our oil and natural
gas production under price sensitive or market price contracts.
We use derivative commodity instruments to manage commodity price risks
associated with future oil and natural gas production. As of September 30, 2005,
we had the following contracts in place:
NATURAL GAS POSITIONS
-------------------------------------------------------------------------------------
VOLUME (MMBTU)
------------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/MMBTU) DAILY TOTAL
----------------------- ------------- ---------------------- ------ ---------
10/05 - 12/05.......... Collar $4.50/$10.75 20,000 1,840,000
10/05 - 12/05.......... Collar $5.00/$10.00 15,000 1,380,000
01/06 - 12/06.......... Collar $5.00/$ 9.51 15,000 5,475,000
01/07 - 12/07.......... Collar $5.00/$ 8.00 10,000 3,650,000
CRUDE OIL POSITIONS
-------------------------------------------------------------------------------------
VOLUME (BBLS)
----------------
REMAINING CONTRACT TERM CONTRACT TYPE STRIKE PRICE ($/BBL) DAILY TOTAL
----------------------- ------------- ---------------------- ------ ---------
10/05 - 12/05.......... Collar $31.00/$44.05 2,000 184,000
Inclusive of the storm implications on our near term forecasted production,
our hedged volume as of September 30, 2005 approximated 10% of our estimated
production from proved reserves for the balance of the terms of the contracts.
Had these contracts been terminated at September 30, 2005, we estimate the
pre-tax loss would have been $38.1 million.
We use a sensitivity analysis technique to evaluate the hypothetical effect
that changes in the market value of crude oil and natural gas may have on the
fair value of our derivative instruments. At September 30, 2005, the potential
change in the fair value of commodity derivative instruments assuming a 10%
increase in the underlying commodity price was a $11.6 million increase in the
combined estimated pre tax 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.
25
ITEM 4. CONTROLS AND PROCEDURES
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND
PROCEDURES
Under the supervision and with the participation of certain members of our
management, including the Chief Executive Officer and Chief Financial Officer,
we completed an evaluation of the effectiveness of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities
Exchange Act of 1934, as amended). Based on this evaluation, our Chief Executive
Officer and Chief Financial Officer believe that the disclosure controls and
procedures were effective as of the end of the period covered by this report
with respect to timely communication to them and other members of management
responsible for preparing periodic reports and all material information required
to be disclosed in this report as it relates to our Company and its consolidated
subsidiaries.
In conjunction with the temporary relocation of our headquarters to
Houston, Texas and establishing a second temporary office in Baton Rouge,
Louisiana due to Hurricane Katrina, we elected to cease hosting our accounting
system in-house and to outsource the host to a third party data center which
allowed us to expedite set up in our temporary multiple location structure and
will expedite the move back to New Orleans when that occurs. The transfer of the
host of the accounting system was not made in response to any pre-existing
deficiency in our internal controls over financial reporting. We continue to
evaluate this hosting relationship as it relates to both the everyday operating
environment of the system as well as our disaster recovery plan. A final
decision as to the permanence of this hosting relationship has not yet been
made. There have been no other changes in our internal control over financial
reporting during the fiscal quarter ended September 30, 2005 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
A control system, no matter how well conceived and operated, can provide
only reasonable, not absolute, assurance that the objectives of the control
system are met. Further, the design of a control system must reflect the fact
that there are resource constraints, and the benefits of controls must be
considered relative to their costs. Because of the inherent limitations in all
control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within the company have been
detected. These inherent limitations include the realities that judgments in
decision-making can be faulty, and that breakdowns can occur because of simple
error or mistake. Additionally, controls can be circumvented by the individual
acts of some persons or by collusion of two or more people. The design of any
system of controls also is based in part upon certain assumptions about the
likelihood of future events, and there can be no assurance that any design will
succeed in achieving its stated goals under all potential future conditions;
over time, controls may become inadequate because of changes in conditions, or
the degree of compliance with the policies or procedures may deteriorate.
Because of the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be detected. Accordingly,
our disclosure controls and procedures are designed to provide reasonable, not
absolute, assurance that the objectives of our disclosure control system are met
and, as set forth above, our Chief Executive Officer and Chief Financial Officer
have concluded, based on their evaluation as of the end of the period, that our
disclosure controls and procedures were sufficiently effective to provide
reasonable assurance that the objectives of our disclosure control system were
met.
26
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibits:
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chairman 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.
27
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 10, 2005 By: /s/ David R. Looney
------------------------------------
David R. Looney
Executive Vice President and
Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)
28
EXHIBIT INDEX
Exhibit
Number Description of Exhibit
------ ----------------------
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chairman 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.
29