Edgar Filing: ENERGY PARTNERS LTD

Form 10-Q for the quarterly period ended September 30, 2007

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2007

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

Commission file number 001-16179

ENERGY PARTNERS, LTD.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

72-1409562

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer

Identification Number)


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

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

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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 5, 2007, there were 31,717,315 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

TABLE OF CONTENTS


		Page
PART I FINANCIAL STATEMENTS

Item 1.	Financial Statements:

	Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006	3

	Consolidated Statements of Operations for the three and nine months ended September 30, 2007 and 2006	4

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2007 and 2006	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	24

Item 4.	Controls and Procedures	26

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	26

Item 1A.	Risk Factors	27

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28

Item 6.	Exhibits	29

Item 1.

FINANCIAL STATEMENTS

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30, 2007			December 31, 2006
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	14,425		$	3,214
Trade accounts receivable		68,173			74,132
Fair value of commodity derivative instruments		534			—
Other receivables		1,863			58,269
Deferred tax assets		878			1,387
Prepaid expenses		2,425			3,570

Total current assets		88,298			140,572
Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties		1,526,971			1,527,304
Less accumulated depreciation, depletion and amortization		(690,083	)		(680,845	)

Net property and equipment		836,888			846,459
Other assets		14,778			13,029
Deferred financing costs—net of accumulated amortization of $720 in 2007 and $6,302 in 2006		10,612			3,785

	$	950,576		$	1,003,845

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	29,943		$	47,154
Accrued expenses		126,085			133,198
Fair value of commodity derivative instruments		419			1,552

Total current liabilities		156,447			181,904
Long-term debt		489,501			317,000
Deferred tax liabilities		58,740			62,451
Asset retirement obligation		71,093			68,767
Fair value of commodity derivative instruments		752			—
Other		1,529			1,453

		778,062			631,575
Stockholders’ equity:
Preferred stock, $1 par value. Authorized 1,700,000 shares; no shares issued and outstanding		—			—
Common stock, par value $0.01 per share. Authorized 100,000,000 shares; issued and outstanding: 2007—43,938,782 shares; 2006—42,501,726 shares		440			425
Additional paid-in capital		372,574			365,313
Accumulated other comprehensive loss—net of deferred taxes of $322 in 2007 and $558 in 2006		(573	)		(994	)
Retained earnings		58,429			64,966
Treasury stock, at cost. 2007—12,239,986 shares; 2006—3,479,814 shares		(258,356	)		(57,440	)

Total stockholders’ equity		172,514			372,270
Commitments and contingencies

	$	950,576		$	1,003,845

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(In thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Revenue:
Oil and natural gas	$	110,327		$	107,390		$	340,313		$	337,594
Other		111			101			254			322

		110,438			107,491			340,567			337,916

Costs and expenses:
Lease operating		19,041			15,230			53,227			44,716
Transportation expense		805			727			1,870			1,538
Exploration expenditures, dry hole costs and impairments		22,692			12,112			81,868			54,491
Depreciation, depletion and amortization		41,718			44,540			133,691			139,166
Accretion		1,127			1,099			3,330			3,250
Taxes, other than on earnings		2,379			5,762			7,448			10,948
General and administrative		12,465			68,457			48,367			93,194
Gain on insurance recoveries		—			—			(8,084	)		—
(Gain) loss on sale of assets		920			—			(6,100	)		419
Other		2,395			667			2,387			2,125

Total costs and expenses		103,542			148,594			318,004			349,847

Business interruption recovery		—			8,293			9,084			31,576
Income (loss) from operations		6,896			(32,810	)		31,647			19,645

Other income (expense):
Interest income		216			328			786			1,080
Interest expense		(12,901	)		(6,907	)		(33,287	)		(17,190	)
Gain (loss) on derivative instruments		(185	)		—			1,722			—
Loss on early extinguishment of debt		—			—			(10,838	)		—

		(12,870	)		(6,579	)		(41,617	)		(16,110	)

Income (loss) before income taxes		(5,974	)		(39,389	)		(9,970	)		3,535
Income taxes		2,011			14,147			3,433			(1,389	)

Net income (loss)		(3,963	)		(25,242	)		(6,537	)		2,146

Basic earnings (loss) per share	$	(0.12	)	$	(0.66	)	$	(0.18	)	$	0.06

Diluted earnings (loss) per share	$	(0.12	)	$	(0.66	)	$	(0.18	)	$	0.05

Weighted average common shares used in
Computing earnings (loss) per share:
Basic		31,734			38,414			35,435			38,254
Incremental common shares
Stock options		—			—			—			195
Warrants		—			—			—			1,759
Restricted share units		—			—			—			262
Performance shares		—			—			—			13

Diluted		31,734			38,414			35,435			40,483

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(In thousands)


	Nine Months Ended September 30,
	2007			2006
Cash flows from operating activities:
Net income (loss)	$	(6,537	)	$	2,146
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		137,021			142,416
(Gain) loss on disposal of assets		(4,592	)		3,497
Non cash-based compensation		6,736			7,968
Non cash loss on early extinguishment of debt		3,398			—
Deferred income taxes		(3,433	)		1,672
Exploration expenditures		72,774			42,108
Amortization of deferred financing costs		954			704
Unrealized gain on derivative contracts		(415	)		—
Gain on insurance recoveries		(8,084	)		—
Other		1,291			1,195
Changes in operating assets and liabilities:
Trade accounts receivable		5,959			3,972
Other receivables		56,406			(44,077	)
Prepaid expenses		1,145			1,379
Other assets		(1,620	)		702
Accounts payable and accrued expenses		(29,428	)		22,576
Other liabilities		(1,666	)		(874	)

Net cash provided by operating activities		229,909			185,384

Cash flows used in investing activities:
Acquisition of business, net of cash acquired		—			(420	)
Insurance recoveries for property, plant and equipment		19,574			—
Property acquisitions		(1,937	)		(15,408	)
Exploration and development expenditures		(264,397	)		(253,983	)
Other property and equipment additions		(680	)		(443	)
Proceeds from sale of oil and natural gas assets		67,543			—

Net cash used in investing activities		(179,897	)		(270,254	)

Cash flows provided by (used in) financing activities:
Deferred financing costs		(11,178	)		(783	)
Repayments of long-term debt		(475,499	)		(30,109	)
Proceeds from long-term debt		648,000			115,000
Purchase of shares into treasury		(200,916	)		—
Exercise of stock options and warrants		792			2,021

Net cash provided by (used in) financing activities		(38,801	)		86,129

Net increase in cash and cash equivalents		11,211			1,259
Cash and cash equivalents at beginning of period		3,214			6,789

Cash and cash equivalents at end of period	$	14,425		$	8,048

See accompanying notes to consolidated financial statements.

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, 2006 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 and current reports on Form 8-K. 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, 2007 and for the three and nine month periods ended September 30, 2007 and 2006 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) MERGERS, ACQUISITIONS AND DIVESTITURES

On June 22, 2006, the Company entered into an agreement and plan of merger (the Merger Agreement) with Stone Energy Corporation (Stone), pursuant to which EPL Acquisition Corp. LLC, a wholly-owned subsidiary of the Company, would acquire all of the shares of Stone for a combination of cash and stock valued at approximately $2.1 billion. Prior to entering into the Merger Agreement, Stone terminated its then existing merger agreement with Plains Exploration and Production Company (Plains) on the same day. As required under the terms of the terminated merger agreement between Stone and Plains, Plains was entitled to a termination fee of $43.5 million, which was advanced by the Company to Plains. On August 28, 2006, Woodside Petroleum, Ltd. (Woodside) announced its intention to commence a tender offer (the Woodside Tender Offer), through its U.S. subsidiary ATS Inc., for all of the Company’s outstanding shares of common stock for $23.00 per share subject to, among other conditions, the Company’s stockholders voting down the proposed Stone acquisition. The Woodside Tender Offer was commenced on August 31, 2006. On September 14, 2006, the Company announced that, on September 13, 2006, the Company’s board of directors (the Board), after review with its independent financial and legal advisors, rejected as inadequate the unsolicited conditional offer by Woodside and recommended that its stockholders not tender their shares. On October 12, 2006 the Company announced that it had terminated the Merger Agreement with Stone and that the Board had directed the Company, assisted by its financial and legal advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of the Company. In conjunction with the termination of the Merger Agreement, the Company paid to Stone $8.0 million, which was included in general and administrative expenses in the fourth quarter of 2006. In addition, the $43.5 million termination fee that was advanced to Plains in June 2006 on behalf of Stone was also expensed during 2006 along with other merger and strategic alternatives related costs of $15.0 million.

On March 12, 2007 the Company announced that the Board had concluded its strategic alternatives process. As a result of this process, the Board, with advice from its financial and legal advisors and management, determined to continue with the execution of the Company’s strategic plan, augmented by a self-tender offer for up to 8,700,000 shares of its common stock at $23.00 per share, the refinancing of its bank credit facility and a tender offer for all of its existing $150 million aggregate principal amount of senior notes due 2010 (the Transactions), and the divestment of selected properties following the completion of the Transactions to reduce debt under the Company’s new bank credit facility. In order to fund the Transactions, the Company undertook a private offering of $450 million of senior unsecured notes and entered into a new bank credit facility. The Company has incurred an additional $9.4 million of financial and legal advisory fees in the first nine months of 2007 related to the exploration of strategic alternatives and the tender offers.

On June 12, 2007, a wholly owned subsidiary of the Company completed its previously announced sale of substantially all of the Company’s onshore South Louisiana assets to Castex Energy 2007, L.P. for $72.0 million in cash. After giving effect to preliminary closing adjustments through September 30, 2007, the net cash proceeds received totaled approximately $67.5 million. The Company has used the proceeds to pay down a portion of its revolving credit facility. As of the closing date of June 12, 2007, the estimated proved reserves of the disposed properties were approximately 1.9 Mmboe. The Company recorded a gain of $6.3 million on the sale.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

In connection with an acquisition in 2002, the Company issued warrants to purchase four million shares of the Company’s common stock. Of the warrants, one million had a strike price of $9.00 and three million had a strike price of $11.00 per share. The warrants became exercisable on January 15, 2003 and expired on January 15, 2007. All remaining warrants were converted in the first quarter of 2007. In addition, former preferred stockholders of the acquired company had 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) exceeded the net present value discounted at 30%. The potential consideration was 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, 35% for the March 1, 2005, 40% for the March 1, 2006 and 50% for the March 1, 2007 determination dates. The contingent consideration could have been 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 could exceed a value of $50 million. The Company capitalized, as additional purchase price, all contingent consideration payments all of which were made in cash. As of March 1, 2007, the final determination date, the Company determined that no final payment was due.

(3) COMMON STOCK

On March 12 2007, the Company’s Board concluded its strategic alternatives process, which resulted in, among other things, an equity self-tender offer for up to 8,700,000 shares of its common stock at $23.00 per share and the authorization for the repurchase of up to $50 million of its common stock prior to April 2008 subject to market conditions. On April 23, 2007 the Company completed the equity self-tender offer and purchased 8,700,000 million shares of its common stock. In addition, during the quarter ended September 30, 2007 the Company acquired 59,500 shares of its common stock, at an average price of $13.71 per share in its stock repurchase program. All of these shares are reflected in treasury stock in the Consolidated Balance Sheets.

(4) EARNINGS PER SHARE

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of warrants and stock options and the potential shares associated with restricted share units and performance shares that would have a dilutive effect on earnings per share.

(5) DERIVATIVE ACTIVITIES

The Company enters into derivative transactions with major financial institutions and others to reduce exposure to fluctuations in the price of oil and natural gas. While the use of these transactions limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. The Company’s Board of Directors has set limitations on the percentage of proved production that the Company can hedge. Crude oil hedges are primarily 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 primarily 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 primarily uses financially-settled crude oil and natural gas zero-cost collars and put options to provide floor prices with varying upside price participation. 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 is above the cap price for the collar. With a put option, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the strike price of the put and the Company has no obligations to the counterparty except for the payment of any option premium. On occasion, the Company has incorporated floors and/or collars into its production sales contracts which are settled under conventional marketing terms.

Prior to the second quarter of 2007, all derivative transactions that qualified for hedge accounting under Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” (Statement 133) as amended by Statement Nos. 137, 138 and 149 were designated on the date the Company entered into each transaction as a hedge of the variability in cash flows associated with the forecasted sale of future oil and natural gas production. After-tax changes in the fair value of a hedge that was highly effective and designated and qualified as a cash flow hedge, to the extent that the hedge was effective, was recorded as Accumulated Other Comprehensive Income (OCI) on the consolidated balance sheet until the sale of the hedged oil and natural gas production occurred. Upon the sale of the underlying hedged production, the net after-tax

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

change in the fair value of the associated hedging transaction recorded in OCI was reversed and the resulting gain or loss on the settlement of the hedge, to the extent that it was effective, was reported in oil and natural gas revenues in the consolidated statement of operations. Once hedge accounting was discontinued prospectively for these existing contracts and while the hedging contracts remain in effect they are carried at their fair value on the Consolidated Balance Sheet until settlement and all subsequent changes in fair value are recognized in the Consolidated Statement of Operations for the period in which the change occurs. At March 31, 2007, following which cash flow hedging was discontinued, the Company had a net $1.5 million after-tax loss recorded in OCI.

Effective April 2, 2007, the Company elected to discontinue hedge accounting on its existing contracts and elected not to designate any additional derivative contracts that were entered into subsequent to that date as cash flow hedges under Statement 133. Derivative contracts are carried at their fair value on the consolidated balance sheet as Fair value of commodity derivative instruments and all unrealized gains and losses are recorded in Gain (loss) on derivative instruments in Other income (expense) in the Statement of Operations and realized gains and losses related to contract settlements subsequent to April 2, 2007 will also be recognized in Other income (expense) in the Consolidated Statement of Operations.

The Company had the following derivative contracts as of September 30, 2007:


Natural Gas Positions
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)		Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)		Daily	Total
10/07 – 12/07	Collar	$	5.00/$8.00	10,000	920,000
10/07	Put	$	6.81	40,000	1,240,000
11/07	Collar	$	7.25/$12.63	20,000	600,000
11/07	Put	$	7.00	20,000	600,000
12/07 – 03/08	Collar	$	6.93/$16.83	35,000	4,270,000
04/08 – 06/08	Collar	$	6.50/$11.15	20,000	1,820,000
11/08 – 12/08	Collar	$	6.82/$15.38	20,000	1,220,000
01/09 – 03/09	Collar	$	6.75/$17.15	10,000	900,000

Crude Oil Positions
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)		Volume (Bbls)
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)		Daily	Total
10/07	Collar	$	55.00/$84.00	500	15,500
11/07 – 12/07	Collar	$	60.00/$89.00	500	30,500
11/07 – 12/07	Collar	$	55.00/$83.13	3,000	183,000
01/08 – 06/08	Collar	$	55.00/$84.68	3,000	546,000
07/08 – 9/08	Put	$	55.00	2,000	184,000
07/08 – 10/08	Collar	$	55.00/$85.65	500	61,500
11/08 – 12/08	Collar	$	55.00/$86.80	2,500	152,500
1/09 – 06/09	Collar	$	55.00/$87.17	3,000	543,000

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

The following table presents information about the components of gain (loss) on derivative instruments for the indicated periods.


	Three Months Ended September 30,			Nine Months Ended September 30,
	2007			2007
Derivative contracts:
Unrealized gain (loss) due to change in fair market value	$	(1,492	)	$	415
Realized gain on settlement		1,307			1,307

Total gain (loss) on derivative instruments	$	(185	)	$	1,722

Settlements of cash flow hedging contracts did not impact crude oil revenues in the three and nine month periods ended September 30, 2006 and reduced natural gas revenues by none and $1.0 million in the three and nine month periods ended September 30, 2006, respectively.

The following tables reconcile the change in accumulated other comprehensive income for the nine month periods ending September 30, 2007 and 2006.


	Nine Months Ended September 30, 2007
	(in thousands)
Accumulated other comprehensive loss as of December 31, 2006—net of taxes of $558				$	(994	)
Net loss	$	(6,537	)
Other comprehensive income—net of tax
Hedging activities
Reclassification adjustments for settled contracts—net of taxes of $91		(161	)
Changes in fair value of outstanding hedging positions existing at March 31, 2007—net of taxes of $(327)		582

Total other comprehensive income		421			421

Comprehensive loss	$	(6,116	)

Accumulated other comprehensive loss as of September 30, 2007—net of taxes of $322				$	(573	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)


	Nine Months Ended September 30, 2006
	(in thousands)
Accumulated other comprehensive loss as of December 31, 2005—net of taxes of $7,098			$	(12,619	)
Net income	$	2,146
Other comprehensive income—net of tax
Hedging activities
Reclassification adjustments for settled contracts—net of taxes of $(247)		439
Changes in fair value of outstanding hedging positions—net of taxes of $(5,851)		10,400

Total other comprehensive income		10,839		10,839

Comprehensive income	$	12,985

Accumulated other comprehensive loss as of September 30, 2006—net of taxes of $1,001			$	(1,780	)

The Company will transfer approximately $0.9 million of pretax net deferred losses in accumulated other comprehensive loss as of September 30, 2007 to earnings during the next three months when the forecasted transactions actually occur. The change in the fair value related to these contracts prior to settlement will also be recorded to earnings.

(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. If both of these requirements are not met, the costs should be expensed. At September 30, 2007, the Company had two projects whose exploratory well costs were suspended, one of which was capitalized for a period greater than one year in the amount of $17.0 million. At September 30, 2006 the Company did not have any projects that were suspended for a period greater than one year.

We analyze proved properties for impairment based on the reserves as determined by our independent reserve engineers. We recognized impairment expense of $7.6 million and $1.8 million during the quarters ending September 30, 2007 and 2006, respectively and $14.6 million and $6.7 million during the nine months ending September 30, 2007 and 2006, respectively. The impairment expense in 2007 was related to impairments at four of our fields which will reach the end of their economic lives earlier than initially expected or had insufficient future cash flow from reserves.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

(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, 2007.


	Nine Months Ended September 30, 2007
	(in thousands)
December 31, 2006	$	68,767
Accretion expense		3,330
Revisions		2,300
Liabilities incurred		2,423
Liabilities settled		(1,581	)

September 30, 2007	$	75,239

At September 30, 2007, and included above, asset retirement obligations required to be settled within the next twelve months of $4.1 million were included in accrued expenses on the Consolidated Balance Sheet.

(8) INDEBTEDNESS

On April 23, 2007 the Company refinanced its bank credit facility with a new $300 million revolving credit facility (the bank credit facility) with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the sale of assets described in Note 2, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. The bank credit facility is secured by substantially all of the Company’s assets. 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 utilization of the bank credit facility. The spread can range from 1.00% to 2.50% above LIBOR and 0% to 0.50% above prime. At September 30, 2007, the Company had $35 million outstanding under the bank credit facility and $165 million available under its borrowing base of $200 million. In addition, the Company pays an annual fee on the unused portion of the bank credit facility ranging between 0.25% to 0.50% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require the Company to: (i) maintain a minimum current ratio, as defined by the bank credit facility, of 1.0x, (ii) maintain a minimum Consolidated EBITDAX to interest ratio, as defined by the bank credit facility, of 2.5x, and (iii) maintain a ratio of long-term debt to Consolidated EBITDAX below 3.5x, which decreases to 3.0x after April 1, 2008. The Company was in compliance with the bank credit facility covenants as of September 30, 2007. 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.

On April 23, 2007 the Company completed an offering of $450 million aggregate principal amount of senior unsecured notes (the Senior Unsecured Notes), consisting of $300 million aggregate principal amount of 9.75% Senior Notes due 2014, with interest payable semi-annually on April 15 and October 15 beginning on October 15, 2007, and $150 million aggregate principal amount of Senior Floating Rate Notes due 2013. The interest rate on the Senior Floating Rate Notes for a particular interest period will be an annual rate equal to the three-month LIBOR plus 5.125%. Interest on the Senior Floating Notes is payable quarterly on January 15, April 15, July 15 and October 15, beginning in July of 2007. The Company may redeem the Senior Unsecured Notes, in whole or in part, prior to their maturity at specific redemption prices including premiums ranging from 4.875% to 0% from 2011 to 2013 and thereafter for the Fixed Rate Notes and premiums ranging from 2% to 0% from 2008 to 2010 and thereafter for the Floating Rate Notes. The indenture governing the Senior Unsecured Notes contains covenants, including but not limited to a covenant limiting the creation of liens securing indebtedness. The Senior Unsecured Notes are not subject to any sinking fund requirements. In November 2007 the Company consummated an exchange offer pursuant to which it exchanged registered senior unsecured notes having substantially identical terms as the privately placed Senior Unsecured Notes.

On May 4, 2007, the Company completed a cash tender offer for its 8.75% Senior Notes due 2010 (the Senior Notes). Approximately $145.5 million of these Senior Notes were repurchased and substantially all of their covenants have been removed.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

A loss on early extinguishment of debt for the refinancing of the bank credit facility and the repurchase of the Senior Notes of approximately $10.8 million was recorded during the nine months ended September 30, 2007. This loss includes the write-off of unamortized deferred financing costs related to the bank credit facility and the Senior Notes as well as the consent fees relating to the tender for the Senior Notes.

(9) 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.

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 three other hurricanes that traversed the Gulf of Mexico and adjacent land areas, nearly all of the Company’s production was shut in at one time or another during the third quarter of 2005 and into 2006. The Company maintained business interruption insurance during this period on its significant properties, including its East Bay field on which recovery of lost revenue continued to accrue until October 2006. Through March 31, 2007, the total business interruption claim on these fields was $62.6 million (all of which had been collected as of that date). In the first quarter of 2007, the Company settled and collected all remaining claims related to Hurricanes Katrina and Rita. Reimbursements received in 2007 exceeded repair costs incurred at that time. Uninsured expenditures, if any, will be recorded to development costs or production costs as incurred, based on the nature of the expenditure. The timing of future repairs will be affected by equipment availability, design and repair planning and permitting.

(10) INCOME TAXES

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

The Company adopted the provisions of FIN 48 on January 1, 2007. The implementation of FIN 48 did not have a material impact on the Company’s financial statements. There were no unrecognized tax benefits as of the date of adoption of FIN 48 and therefore, there is no anticipated effect upon the Company’s effective tax rate. Interest, if any, under FIN 48 will be classified in the financial statements as a component of interest expense and statutory penalties, if any, will be classified as a component of general and administrative expense.

As of January 1, 2007, the Company’s 2003-2006 income tax years remain subject to examination by the Internal Revenue Service, as well as the Louisiana Department of Revenue. In addition, Texas Franchise Tax calendar years 2002-2006 remain subject to examination.

(11) NEW ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurements” (Statement 157). Statement 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Statement 157 applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, Statement 157 does not require any new fair value measurements. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently assessing what impact Statement 157 may have on the Company’s financial position, results of operations or cash flows.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

permits entities to choose to measure many financial instruments and certain other items at fair value. Statement 159 is expected to expand the use of fair value measurement, which is consistent with the Board’s long-term measurement objectives for accounting for financial instruments. Statement 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of Statement 157. The Company is currently assessing what impact Statement 159 may have on the Company’s financial position, results of operations or cash flows.

(12) RELATED PARTY

One of the Company’s directors is a senior managing director of Evercore Group L.L.C. (Evercore). Evercore provided financial advisory service to the Company in connection with the Stone transaction, the Woodside offer and the Company’s exploration of strategic alternatives. Evercore received fees of $1.6 million in 2006 in connection with financial advisory services related to the Stone transaction and the consideration of the unsolicited offer from Woodside. In addition, a $7.0 million fee was due to Evercore upon the earlier of the consummation of a transaction or September 5, 2007, of which $2.3 million was accrued during 2006 and the remaining $4.7 million was accrued in the first nine months of 2007 and paid in September 2007.

(13) SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In connection with the sale of the Senior Unsecured Notes discussed above, all of the Company’s current active subsidiaries (the Guarantor Subsidiaries) jointly, severally and unconditionally guaranteed the payment obligations under the Senior Unsecured Notes. The following supplemental financial information sets forth, on a consolidating basis, the balance sheet, statement of operations and cash flow information for Energy Partners, Ltd. (Parent Company Only) and for the Guarantor Subsidiaries. The Company has not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries because management has determined that such information is not material to investors.

The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements, although the Company believes that the disclosures made are adequate to make the information presented not misleading. Certain reclassifications were made to conform all of the financial information to the financial presentation on a consolidated basis. The principal eliminating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

Supplemental Condensed Consolidating Balance Sheet

As of September 30, 2007


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	14,425		$	—		$	—		$	14,425
Accounts receivable		(52,139	)		122,709			—			70,570
Other current assets		3,175			128			—			3,303

Total current assets		(34,539	)		122,837			—			88,298
Property and equipment		1,295,328			231,643			—			1,526,971
Less accumulated depreciation, depletion and amortization		(581,687	)		(108,396	)		—			(690,083	)

Net property and equipment		713,641			123,247			—			836,888
Investment in affiliates		201,675			(85	)		(201,590	)		—
Notes receivable, long-term		—			221,909			(221,909	)		—
Other assets		25,267			123			—			25,390

	$	906,044		$	468,031		$	(423,499	)	$	950,576

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	152,867		$	3,161		$	—		$	156,028
Fair value of commodity derivative instruments		419			—			—			419

Total current liabilities		153,286			3,161			—			156,447
Long-term debt		489,501			221,909			(221,909	)		489,501
Other liabilities		90,743			41,371			—			132,114

		733,530			266,441			(221,909	)		778,062
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		440			98			(98	)		440
Additional paid-in capital		372,574			68			(68	)		372,574
Accumulated other comprehensive loss		(573	)		—			—			(573	)
Retained earnings		58,429			201,421			(201,421	)		58,429
Treasury stock		(258,356	)		—			—			(258,356	)

Total stockholders’ equity		172,514			201,590			(201,589	)		172,514

	$	906,044		$	468,032		$	(423,499	)	$	950,576

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

Supplemental Condensed Consolidated Statement of Operations

Nine Months Ended September 30, 2007


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenue:
Oil and natural gas	$	271,802		$	68,511		$	—		$	340,313
Other		56,349			120			(56,215	)		254

		328,151			68,631			(56,215	)		340,567
Costs and expenses:
Lease operating		81,633			(26,536	)		—			55,097
Exploration expenditures		70,826			11,042			—			81,868
Depreciation, depletion and amortization		116,012			21,009			—			137,021
Taxes, other than on earnings		357			7,091			—			7,448
General and administrative		47,349			12,268			(11,250	)		48,367
Gain on insurance recoveries		(8,084	)		—			—			(8,084	)
Gain on sale of assets		(4,892	)		(1,208	)		—			(6,100	)
Other		2,387			—			—			2,387

Total costs and expenses		305,588			23,666			(11,250	)		318,004

Business interruption recovery		9,084			—			—			9,084
Income from operations		31,647			44,965			(44,965	)		31,647

Other income (expense):
Interest expense, net		(32,501	)		—			—			(32,501	)
Unrealized gain on derivative instruments		1,722			—			—			1,722
Loss on early extinguishment of debt		(10,838	)		—			—			(10,838	)

		(41,617	)		—			—			(41,617	)

Loss before income taxes		(9,970	)		44,965			(44,965	)		(9,970	)
Income taxes		3,433			—			—			3,433

Net loss	$	(6,537	)	$	44,965		$	(44,965	)	$	(6,537	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

Supplemental Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2007


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)
Net cash provided by operating activities	$	215,137		$	14,772		$	—	$	229,909
Cash flows used in investing activities:
Insurance recoveries from property, plant and equipment		19,574			—			—		19,574
Property acquisitions		(1,513	)		(424	)		—		(1,937	)
Exploration and development expenditures		(250,049	)		(14,348	)		—		(264,397	)
Other property and equipment additions		(680	)		—			—		(680	)
Proceeds from sale of oil and natural gas assets		67,543			—			—		67,543

Net cash used in investing activities		(165,125	)		(14,772	)		—		(179,897	)
Cash flows used in financing activities:
Deferred financing costs		(11,178	)		—			—		(11,178	)
Repayments of long-term debt		(475,499	)		—			—		(475,499	)
Proceeds from long-term debt		648,000			—			—		648,000
Purchase of shares into treasury		(200,916	)		—			—		(200,916	)
Exercise of stock options and warrants		792			—			—		792

Net cash used in financing activities		(38,801	)		—			—		(38,801	)

Net increase in cash and cash equivalents		11,211			—			—		11,211
Cash and cash equivalents at beginning of period		3,214			—			—		3,214

Cash and cash equivalents at end of period	$	14,425		$	—		$	—	$	14,425

(14) CONTINGENCIES

On September 12, 2006, Thomas Farrington, a purported stockholder of the Company, filed a putative class action suit against the Company, all of the Company’s directors, EPL Acquisition Corp. LLC, and Stone in the Delaware Court (the Farrington Action). As amended on October 19, 2006, the complaint in the Farrington Action alleged that the Company’s directors breached their fiduciary duties by agreeing to the termination fee provisions in the Merger Agreement, adopting the sixth-month stockholders rights agreement, amending and extending coverage to all full time employees of its change of control severance arrangements, and paying a fee to Stone in connection with the termination of the Merger Agreement. Farrington also alleged that the Company’s directors failed to adequately disclose material information relevant to the Company stockholders’ decision whether to accept the Woodside Tender Offer. This case was dismissed on the motion of all parties in September 2007. On July 26, 2007, plaintiff filed a petition for an award of attorneys’ fees and expenses. A trial on plaintiff’s fee petition is scheduled for November 29, 2007. The Company believes the claim is without merit and intends to vigorously oppose the amount sought in the petition. The Company does not expect this claim to have a material adverse effect on the financial position, results of operations or liquidity of the Company.

In June 2007 the Company met with representatives of the U.S. Attorney for the Eastern District of Louisiana in New Orleans, the U.S. Environmental Protection Agency and the U.S. Coast Guard and was informed that they are conducting an investigation into possible criminal violations arising out of on-site inspections in the Company’s East Bay field in November 2005 and February 2006. The Company intends to cooperate fully with the government’s investigation and operations in the field remain unaffected by the investigation. It does not expect the outcome to have a material adverse effect on the financial position, results of operations or liquidity of the Company.

In the ordinary course of business, the Company is a defendant in various other 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

(15) RECLASSIFICATIONS

Certain reclassifications have been made to the prior period financial statements in order to conform to the classification adopted for reporting in fiscal 2007.

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 Shelf and deepwater Gulf of Mexico as well as the Gulf Coast onshore region.

In the first nine months of 2007 we continued to strive toward implementing our long-term growth strategy to increase our oil and natural gas reserves and production while focusing on reducing finding and development costs and operating costs to remain competitive with our industry peers. We are implementing this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential. We also evaluate acquisition opportunities including acquisitions in our core focus area which includes the Gulf of Mexico and onshore Gulf Coast regions as a complement to the exploration and development activities we have budgeted for that area. Our drilling program is predominately comprised of moderate risk, higher or moderate reserve potential opportunities as well as some high risk, higher reserve potential opportunities and low risk lower reserve potential opportunities.

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, 2006, includes a discussion of our critical accounting policies, which have not changed significantly since the end of the fiscal year.

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. Our policy is to fund our exploration and development expenditures with internally generated cash flow, which allows us to preserve our balance sheet to finance acquisitions and other capital intensive projects that might result from exploration and development activities. However, from time to time, we may use our bank credit facility to fund working capital needs.

On June 12, 2007, one of our wholly owned subsidiaries completed a previously announced sale of substantially all of our onshore South Louisiana producing assets to Castex Energy 2007, L.P. for $72.0 million in cash. After giving effect to preliminary closing adjustments through September 30, 2007, the net cash proceeds received totaled approximately $67.5 million. We have used the proceeds to pay down a portion of our revolving credit facility. As of the closing date of June 12, 2007, the estimated proved reserves of the disposed properties were approximately 1.9 Mmboe. The Company recorded a gain of $6.3 million on the sale. We have included the results of operations from the onshore South Louisiana assets sold in our consolidated financial statements through the closing date of June 12, 2007.

Effective April 2, 2007, we elected to discontinue hedge accounting on our existing contracts and elected not to designate any additional hedging contracts that were entered into subsequent to that date as cash flow hedges under Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” (“Statement 133”). Derivative contracts are carried at their fair value on the consolidated balance sheet as Fair value of commodity derivative instruments and all unrealized gains and losses are recorded in Unrealized gain on derivative instruments in Other income (expense) in the Statement of Operations and realized gains and losses related to contract settlements subsequent to April 2, 2007 will also be recognized in Other income (expense) in the Consolidated Statement of Operations.

On June 22, 2006, we entered into an agreement and plan of merger (the “Merger Agreement”) with Stone Energy Corporation (“Stone”), pursuant to which EPL Acquisition Corp. LLC, a wholly-owned subsidiary, would acquire all of the shares of Stone for a combination of cash and stock valued at approximately $2.1 billion. Prior to entering into the Merger Agreement, Stone terminated its then existing merger agreement with Plains Exploration and Production Company (“Plains”) on the same day. As required under the terms of the terminated merger agreement between Stone and Plains, Plains was entitled to a termination fee of $43.5 million, which was advanced by us to Plains and was included in other assets in the Consolidated Balance Sheet at June 30, 2006. On August 28, 2006, Woodside Petroleum, Ltd. (“Woodside”) announced its intention to commence a tender offer (the “Woodside Tender Offer”), through its U.S. subsidiary ATS Inc., for all of our outstanding shares of common stock for $23.00 per share subject to, among other conditions, our stockholders voting down the proposed Stone acquisition. The Woodside Tender Offer was commenced on August 31, 2006. On September 14, 2006, we announced that, on September 13, 2006, our board of directors (the “Board”), after review with our independent financial and legal advisors, rejected as inadequate the unsolicited conditional offer by Woodside and recommended that our stockholders not tender their shares. On October 12, 2006 we announced that we had terminated the Merger Agreement with Stone and that the Board had directed us, assisted by our financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of the Company. The Woodside Tender Offer expired in November 2006. On March 12, 2007 we announced that we had completed our strategic alternatives process and that we intended to initiate a self-tender offer for 8,700,000 of our common shares, refinance our bank credit facility and repurchase our 8.75% senior notes (the “Senior Notes”) through a concurrent debt tender and consent solicitation offer (the “Transactions”). In order to fund the Transactions, we undertook a private offering of $450 million of Senior Unsecured Notes and entered into a new bank credit facility. In addition, we announced our plans to divest selected properties the proceeds from which would be used to reduce debt following the completion of the Transactions. In conjunction with the termination of the Merger Agreement, we paid $8.0 million to Stone, which was included in general and administrative expenses in the fourth quarter of 2006. In addition, the $43.5 million termination fee that was advanced to Plains in June 2006 on behalf of Stone was expensed in 2006 along with other merger and strategic alternatives related costs of $15.0 million. We have incurred an additional $9.4 million of legal and financial advisory fees in the first nine months of 2007 related to the exploration of strategic alternatives and the tender offers.

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, 2005 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. 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 three other hurricanes that traversed the Gulf of Mexico and adjacent land areas, nearly all of the Company’s production was shut in at one time or another during the third quarter of 2005 and into 2006. We have recognized a total of $62.6 million for business interruption recoveries of which $32.9 million and $20.6 million were recorded in the statement of operations in 2006 and fourth quarter of 2005, respectively and an additional $9.1 million was recorded in the first quarter of 2007 upon the final settlement of the Hurricane Katrina claim. All insurance receivables related to these hurricanes have been collected.

RESULTS OF OPERATIONS

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2007			2006		2007			2006
Net production (per day):
Oil (Bbls)		8,271			8,092		8,862			7,824
Natural gas (Mcf)		92,579			103,975		98,322			106,162
Total barrels of oil equivalent (Boe)		23,701			25,421		25,249			25,518
Average sales prices, net of hedging in 2006:
Oil (per Bbl)	$	70.89		$	65.57	$	61.09		$	62.29
Natural gas (per Mcf)		6.62			6.12		7.17			7.06
Total (per Boe)		50.60			45.92		49.37			48.46
Impact of hedging:
Oil (per Bbl)	$	—		$	—	$	—		$	—
Natural gas (per Mcf)		—			—		—			(0.03	)
Oil and natural gas revenues (in thousands):
Oil	$	53,941		$	48,814	$	147,802		$	133,048
Natural gas		56,386			58,576		192,511			204,546
Total		110,327			107,390		340,313			337,594
Average costs (per Boe):
Lease operating expense	$	8.73		$	6.51	$	7.72		$	6.42
Depreciation, depletion and amortization		19.13			19.04		19.40			19.98
Accretion expense		0.52			0.47		0.48			0.46
Taxes, other than on earnings		1.09			2.46		1.08			1.57
General and administrative		5.72			29.27		7.02			13.38
Increase (decrease) in oil and natural gas revenues between periods presented due to:
Changes in prices of oil	$	3,960				$	(2,564	)
Changes in production volumes of oil		1,167					17,318

Total increase in oil sales		5,127					14,754
Changes in prices of natural gas	$	4,854				$	3,156
Changes in production volumes of natural gas		(7,044	)				(15,191	)

Total decrease in natural gas sales		(2,190	)				(12,035	)

REVENUES AND NET INCOME

Our oil and natural gas revenues increased to $110.3 million in the third quarter of 2007 from $107.4 million in the third quarter of 2006. During the quarter oil and natural gas prices increased but this increase was partially offset by decreased natural gas production due primarily to the sale of substantially all of our onshore South Louisiana assets on June 12, 2007 combined with natural reservoir declines and offset by production from new wells.

Our oil and natural gas revenues increased to $340.3 million in the first nine months of 2007 from $337.6 million in the first nine months of 2006. Although total production decreased due to the reasons mentioned above, the increase in revenue was largely due to an increase in oil production during the period as well as a slight increase in natural gas prices yielding a higher price per Boe.

We recognized a net loss of $4.0 million in the third quarter of 2007 compared to a net loss of $25.2 million in the third quarter of 2006. The overall change from period to period was primarily attributable to one time expensed costs of $46.5 million incurred during the third quarter of 2006 relating to the terminated Merger Agreement with Stone offset by changes in operating costs discussed below.

We recognized a net loss of $6.5 million in the first nine months of 2007 compared to net income of $2.1 million in the first nine months of 2006. The overall change was largely due to higher lease operating expenses, exploration expenditures including dry hole costs and impairments and financing costs discussed below. This was partially offset by one time

expensed costs of $46.5 million incurred during the nine months ended September 30, 2006 relating to the terminated Merger Agreement with Stone and the gain on sale of substantially all of our onshore South Louisiana assets.

OPERATING EXPENSES

Operating expenses during the three and nine month periods ended September 30, 2007 and 2006 were affected by the following:

•

Lease operating expense (“Loe”) increased to $19.0 million in the third quarter of 2007 compared with $15.2 million in the third quarter of 2006. Loe increased to $53.2 million in the first nine months of 2007 compared with $44.7 million in the first nine months of 2006. Loe also increased on a Boe basis for both the three and nine month periods ended September 30, 2007. These increases are primarily a result of a general increase in new wells coming on stream in new fields combined with production declines from existing fields with fixed costs and workover, maintenance and pipeline repair costs. Also contributing to the increase in the first nine months of 2007 was the gradual restart of storm shut-in production throughout 2006.

•

Taxes, other than on earnings, were $2.4 million in the third quarter of 2007 compared with $5.8 million in the third quarter of 2006. Taxes, other than on earnings, decreased to $7.4 million in the first nine months of 2007 from $10.9 million in the first nine months of 2006. The decrease is due to lower natural gas production volumes within the state of Louisiana which is largely the result of the sale of onshore Louisiana assets in June 2007. These taxes are expected to fluctuate from period to period depending on our remaining production volumes from non-federal leases and the commodity prices received.

•

Exploration expenditures, including dry hole costs and impairments, increased to $22.7 million in the third quarter of 2007 from $12.1 million in the third quarter of 2006. The expense in the third quarter of 2007 is comprised of $13.4 million of costs for three exploratory wells or portions thereof which were found to be not commercially productive, $7.6 million from the impairment of properties at two of our fields which had reached the end of their economic lives sufficient future cashflows from reserves and $1.7 million of seismic expenditures and delay rentals. The expense in the third quarter of 2006 was comprised of $7.1 million of costs for exploratory wells or portions thereof which were found to be not commercially productive, $1.8 million from the impairment of properties and $3.2 million of seismic expenditures and delay rentals.

Exploration expenditures, including dry hole costs and impairments, increased to $81.9 million in the first nine months of 2007 from $54.5 million in the first nine months of 2006. The expense in the first nine months of 2007 is comprised of $58.1 million of costs for nine exploratory wells or portions thereof which were found to be not commercially productive, $14.6 million from the impairment of properties at four of our fields which had reached the end of their economic lives sufficient future cashflows from reserves and $9.2 million of seismic expenditures and delay rentals. The expense in the first nine months of 2006 was comprised of $35.1 million of costs for exploratory wells or portions thereof which were found to be not commercially productive, $6.7 million of property impairments and $12.7 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, the cost of services to drill wells and the level of success we achieve in exploratory drilling activities.

•

Depreciation, depletion and amortization (“DD&A”) decreased to $41.7 million in the third quarter of 2007 from $44.5 million in the third quarter of 2006. DD&A decreased to $133.7 million in the first nine months of 2007 from $139.2 million in the first nine months of 2006. This decrease was due to an overall decrease in production previously mentioned. For the year to date period there is also a decline in DD&A per Boe as there was a higher percentage of production contribution from fields that had lower DD&A burdens. Some fields carry a higher burden than others; therefore, changes in the sources of our production will directly impact this expense.

•

General and administrative expenses decreased to $12.5 million in the third quarter of 2007 from $68.5 million in the third quarter of 2006. Included in this expense is stock based compensation of $3.0 million and $3.1 million in the third quarters of 2007 and 2006, respectively. General and administrative expenses decreased to $48.4 million in the first nine months of 2007 from $93.2 million in the first nine months of 2006. Included in this expense is stock based compensation of $7.3 million and $7.7 million in the first nine months of 2007 and 2006, respectively. The overall decrease in both the three and nine month periods was primarily attributable to one time expensed costs of $46.5 million incurred during the third quarter of 2006 relating to the terminated Merger Agreement with Stone as well as legal and financial advisory costs of $8.2 million in the third quarter of 2006 associated with the unsolicited Woodside offer.

OTHER INCOME AND EXPENSE

Interest expense increased to $12.9 million in the third quarter of 2007 from $6.9 million in the third quarter of 2006. Interest expense increased to $33.3 million in the first nine months of 2007 from $17.2 million in the first nine months of 2006. The increase was primarily attributable to the net increase in the average borrowings due to the repurchase of $145.5 million in aggregate principal amount of the $150 million 8.75% Senior Notes completed in May 2007 and the issuance of the $450 million in aggregate principal amount of Senior Unsecured Notes in April 2007 combined with borrowings on our bank credit facility. Also included in the expense for the first nine months of 2007 is a $2.3 million commitment fee paid in April 2007 for the availability of a bridge loan to facilitate the refinancings, had it been needed.

LIQUIDITY AND CAPITAL RESOURCES

Our cash flows from operations totaled $229.9 million in the first nine months of the year, which included a $56.4 million change in other receivables as a result of our hurricane insurance collections during the period. In addition, net cash of $38.8 million was used in financing activities during the first nine months of the year resulting from the Transactions previously discussed. While 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, from time to time, due to such things as commodity price fluctuations and capital requirements from exploration successes, we use our bank credit facility to fund additional working capital needs. Our cash on hand at September 30, 2007 was $14.4 million. Our future internally generated cash flows will depend on our rates of production, including those provided by our exploratory and development drilling program, as well as the prices we receive for oil and natural gas.

On April 23, 2007 we completed a refinancing of our bank credit facility with a new $300 million revolving credit facility (the “bank credit facility”) with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the sale of assets described previously, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. The bank credit facility is secured by substantially all of our assets. 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 1.00% to 2.5% above LIBOR and 0% to 0.50% above prime. In addition we pay an annual fee on the unused portion of the bank credit facility ranging between 0.25% to 0.50% 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 by our bank credit facility, of 1.0x, (ii) maintain a minimum Consolidated EBITDAX to interest ratio, as defined by our bank credit facility, of 2.5x, and (iii) maintain a ratio of long-term debt to Consolidated EBITDAX below 3.5x, which decreases to 3.0x after April 1, 2008. On April 30, 2007 we borrowed $70.0 million under our bank credit facility to fund a portion of the equity self-tender offer. As of November 5, 2007, we had a borrowing base of $200 million and $145 million available under our bank credit facility. We were in compliance with the bank credit facility covenants as of September 30, 2007.

Also on April 23, 2007 we completed an offering of $450 million aggregate principal amount of senior unsecured notes (the “Senior Unsecured Notes”), consisting of $300 million aggregate principal amount of 9.75% Senior Notes due 2014, with interest payable semi-annually on April 15 and October 15 beginning on October 15, 2007, and $150 million aggregate principal amount of Senior Floating Rate Notes due 2013. The interest rate on the Senior Floating Rate Notes for a particular interest period will be an annual rate equal to the three-month LIBOR plus 5.125%. Interest on the Senior Floating Notes are payable quarterly on January 15, April 15, July 15 and October 15, beginning in July of 2007. We may redeem the Senior Unsecured Notes, in whole or in part, prior to their maturity at specific redemption prices including premiums ranging from 4.875% to 0% from 2011 to 2013 and thereafter for the Fixed Rate Notes and premiums ranging from 2% to 0% from 2008 to 2010 and thereafter for the Floating Rate Notes. The indenture governing the Senior Unsecured Notes contains covenants, including but not limited to, a covenant limiting the creation of liens securing indebtedness. The Senior Unsecured Notes are not subject to any sinking fund requirements. In November 2007 we consummated an exchange offer pursuant to which we exchanged registered senior unsecured notes having substantially identical terms as the privately placed Senior Unsecured Notes.

On May 4, 2007, we completed a cash tender offer for our Senior Notes. Approximately $145.5 million of these Senior Notes were repurchased and substantially all of their covenants have been removed.

Net cash of $179.9 million used in investing activities in the first nine months of 2007 consisted primarily of oil and natural gas exploration and development expenditures offset by proceeds of $67.5 million from the sale of onshore South Louisiana oil and

natural gas assets in June 2007 and proceeds of $19.6 million from the settlement of our Hurricane Rita insurance claim in March 2007. Dry hole costs resulting from exploration expenditures are excluded from operating cash flows and included in investing activities. During the first nine months of 2007, we completed 19 drilling operations, 11 of which were successful, and 22 recompletion/workover operations all of which were successful. During the first nine months of 2006, we completed 21 drilling operations, 16 of which were successful, and 32 recompletion/workover operations, 28 of which were successful.

Our 2007 capital exploration and development budget is focused on moderate risk and higher risk exploratory activities on undeveloped leases and our proved properties combined with exploitation and development activities on 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. Currently, our exploration and development budget for 2007 is $300 million. We are currently reviewing our spending expectations for the remainder of the year and estimate that our total capital expenditures for 2007 could total between $325 million and $350 million to fund development costs as a result of exploration success and to fund leasehold costs for leases that may be awarded prior to year-end as a result of our high bids in the October 2007 MMS lease sale. We do not budget for acquisitions. During the first nine months of 2007, capital and exploration expenditures were approximately $267.5 million. 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, we may change our total 2007 capital expenditures.

On June 12, 2007, one of our wholly owned subsidiaries completed its previously announced sale of substantially all of our onshore South Louisiana assets to Castex Energy 2007, L.P. for $72.0 million in cash. After giving effect to closing adjustments through September 30, 2007, the cash proceeds received totaled approximately $67.5 million. We have used the proceeds to pay down a portion of our revolving credit facility. As of the closing date of June 12, 2007, the estimated proved reserves were approximately 1.9 Mmboe. We have also been marketing selected offshore assets but can give no assurance of the occurrence or timing of any such sale or sales of the assets being so marketed or to the value we may receive.

In addition, the Board has also authorized an open market share repurchase program of up to $50 million through April 2008, subject to business and market conditions. We may use borrowings under our bank credit facility to fund the repurchase program. As of November 5, 2007, 59,500 shares have been purchased for $0.8 million pursuant to this authorization.

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 combined with temporary borrowings under our bank credit facility 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, 2006 included a discussion of our contractual obligations. There have been no material changes to that disclosure during the nine months ended September 30, 2007 other than those resulting from the Transactions discussed herein. 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 September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurements” (“Statement 157”). Statement 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Statement 157 applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, Statement 157 does not require any new fair value measurements. However, for some entities, the application of Statement 157 will change current practice. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently assessing what impact Statement 157 may have on our financial position, results of operations or cash flows.

In February 2007, the FASB issued Statement of Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115” (“Statement 159”). Statement 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Statement 159 is expected to expand the use

of fair value measurement, which is consistent with the Board’s long-term measurement objectives for accounting for financial instruments. Statement 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of Statement 157. We are currently assessing what impact Statement 159 may have on our financial position, results of operations or cash flows.

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 or under the Securities and Exchange Act of 1934 and other written or oral statements made by us or on behalf, are forward-looking statements. Forward-looking statements are subject to risks and uncertainties. Although we believe that in making such statements our expectations are based on reasonable assumptions, such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected.

Except for any obligation to disclose material information under U.S. federal securities laws, we do not undertake any obligation to release publicly any revisions to any forward-looking statements, to report events or circumstances after the date of this document, or to report the occurrence of unanticipated events.

Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will,” “would,” “should,” “plans,” “likely,” “expects,” “anticipates,” “intends,” “believes,” “estimates,” “thinks,” “may,” and similar expressions, are forward-looking statements. The following important factors, in addition to those discussed under “Risk Factors” in our Form 10-K and elsewhere in this document, could affect the future results of the energy industry in general and could cause those results to differ materially from those expressed in or implied by such forward-looking statements:

•

uncertainties inherent in the development and production of and exploration for oil and natural gas and in estimating reserves;

•

the effects of our substantial indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;

•

unexpected future capital expenditures (including the amount and nature thereof);

•

the effects of adverse weather conditions, such as hurricanes and tropical storms;

•

impact of oil and natural gas price fluctuations;

•

the effects of competition;

•

the success of our risk management activities;

•

the availability (or lack thereof) of acquisition or combination opportunities;

•

the impact of current and future laws and governmental regulations;

•

environmental liabilities that are not covered by an effective indemnity or insurance; and

•

general economic, market or business conditions.

All written and oral forward-looking statements attributable to us or persons acting on behalf of us are expressly qualified in their entirety by such factors. We refer you specifically to the section “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2006 and this Quarterly Report on Form 10-Q. 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, 2007, $185.0 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 2007, 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 $0.5 million based on total variable debt outstanding during the period. If market interest rates had averaged 1% lower in the third quarter of 2007, interest expense for the period on variable rate debt would have decreased, and net income before income taxes would have increased by approximately $0.5 million.

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. For the periods presented we sold 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, 2007, we had the following derivative contracts in place:


Natural Gas Positions
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)		Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)		Daily	Total
10/07 – 12/07	Collar	$	5.00/$8.00	10,000	920,000
10/07	Put	$	6.81	40,000	1,240,000
11/07	Collar	$	7.25/$12.63	20,000	600,000
11/07	Put	$	7.00	20,000	600,000
12/07 – 03/08	Collar	$	6.93/$16.83	35,000	4,270,000
04/08 – 06/08	Collar	$	6.50/$11.15	20,000	1,820,000
11/08 – 12/08	Collar	$	6.82/$15.38	20,000	1,220,000
01/09 – 03/09	Collar	$	6.75/$17.15	10,000	900,000

Crude Oil Positions
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)		Volume (Bbls)
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)		Daily	Total
10/07	Collar	$	55.00/$84.00	500	15,500
11/07 – 12/07	Collar	$	60.00/$89.00	500	30,500
11/07 – 12/07	Collar	$	55.00/$83.13	3,000	183,000
01/08 – 06/08	Collar	$	55.00/$84.68	3,000	546,000
07/08 – 9/08	Put	$	55.00	2,000	184,000
07/08 – 10/08	Collar	$	55.00/$85.65	500	61,500
11/08 – 12/08	Collar	$	55.00/$86.80	2,500	152,500
1/09 – 06/09	Collar	$	55.00/$87.17	3,000	543,000

Volumes covered under these contracts, as of September 30, 2007, approximated 29% of our estimated production from proved reserves for the balance of the terms of the contracts. As of April 2, 2007, we elected to discontinue hedge accounting and therefore, not to designate any commodity derivative contracts as cash flow hedges under Statement 133. All derivative contracts are carried at their fair value on the consolidated balance sheet as assets or liabilities. Accordingly we recognize all unrealized and realized gains and losses related to these contracts in the statement of operations as income or expense.

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, 2007, the potential change in the fair value of commodity derivative instruments for the remainder of the contract terms assuming a 10% increase in the underlying commodity price was a $6.3 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.

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 principal executive and financial officer and principal accounting 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 principal executive and financial officer and principal accounting officer believe that the disclosure controls and procedures were effective as of the end of and during the period covered by this report with respect to timely communication to them and other members of management responsible for preparing periodic reports and all material information required to be disclosed in this report as it relates to our Company and its consolidated subsidiaries. There was no change in our internal control over financial reporting during the fiscal quarter ended September 30, 2007 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 principal executive and financial officer and principal accounting officer have concluded, based on their evaluation as of the end of and during the period, that our disclosure controls and procedures were effective.

Part II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

On September 12, 2006, Thomas Farrington, a purported stockholder of the Company, filed a putative class action suit against the Company, all of the Company’s directors, EPL Acquisition Corp. LLC, and Stone in the Delaware Court (the Farrington Action). As amended on October 19, 2006, the complaint in the Farrington Action alleged that the Company’s directors breached their fiduciary duties by agreeing to the termination fee provisions in the Merger Agreement, adopting the sixth-month stockholders rights agreement, amending and extending coverage to all full time employees of its change of control severance arrangements, and paying a fee to Stone in connection with the termination of the Merger Agreement. Farrington also alleged that the Company’s directors failed to adequately disclose material information relevant to the Company stockholders’ decision whether to accept the Woodside Tender Offer. This case was dismissed on the motion of all parties in September 2007. On July 26, 2007, plaintiff filed a petition for an award of attorneys’ fees and expenses. A trial on plaintiff’s fee petition is scheduled for November 29, 2007. We believe the claim is without merit and intend to vigorously oppose the amounts sought in the petition.

investigation. We do not expect the outcome to have a material adverse effect on our financial position, results of operations or liquidity.

Item 1A.

RISK FACTORS

With the exception of the following risk factor, there have been no changes to our risk factors as presented in our Form 10-K for the year ended December 31, 2006.

Our substantial indebtedness and increased interest expense could impair our financial condition and our ability to fulfill our obligations.

As of September 30, 2007, we had total indebtedness of approximately $489.5 million. Most of this indebtedness was incurred in April 2007, and, our interest expense has increased significantly. In addition, a significant portion of our indebtedness has a floating rate of interest, which may increase over time.

Our indebtedness could have important consequences to you. For example, it could:

•

Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

•

Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;

•

Reduce our ability to withstand a downturn in our business or the economy generally;

•

Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;

•

Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

•

Place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

If we are unable to meet our debt service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or not at all.

Actual or alleged violations of environmental laws and regulations could result in restrictions on our operations or civil or criminal liability.

Our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes are subject to regulation under various federal, state and local laws and regulations governing the protection of the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief. Changes in environmental rules and regulations occur regularly, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially affect our operations and financial position, as well as those in the oil and natural gas industry in general.

In June 2007 we met with representatives of the U.S. Attorney for the Eastern District of Louisiana in New Orleans, the U.S. Environmental Protection Agency and the U.S. Coast Guard and were informed that they are conducting an investigation into possible criminal violations arising out of on-site inspections in our East Bay field in November 2005 and February 2006.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities


Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares or Approximate Dollar Value that May Yet Be Purchased Under the Plans or Programs (in thousands)
7/1/07 – 7/31/07	—	$	n/a	n/a		n/a
8/1/07 – 8/31/07 (1)	56,500		13.66	56,500	$	49,228
9/1/07 – 9/30/07 (1)	3,000		14.73	3,000		49,184

Total	59,500	$	13.71	59,500	$	49,184

(1)

In March 2007, our Board authorized the repurchase of up to $50 million of our common stock prior to April 2008 subject to business and market conditions. During the quarter ended September 30, 2007 the Company acquired 59,500 shares of its common stock in its stock repurchase program. All of these shares are reflected in treasury stock in the Consolidated Balance Sheets.

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 Certification

*	filed herewith

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 7, 2007	By:	/s/ Joseph T. Leary
		Joseph T. Leary
		Executive Vice President and Chief Financial Officer
		(authorized officer and principal financial officer)

EXHIBIT INDEX


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 Certification

*	Filed herewith

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