Edgar Filing: ENERGY PARTNERS LTD

Form 10-Q

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, 2006

¨	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 1, 2006, there were 38,952,550 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, 2006 and December 31, 2005	3

	Consolidated Statements of Operations for the three and nine months ended September 30, 2006 and 2005	4

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and 2005	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27

Item 4.	Controls and Procedures	27

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	28

Item 1A.	Risk Factors	29

Item 6.	Exhibits	29

Item 1. FINANCIAL STATEMENTS

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30, 2006			December 31, 2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	8,048		$	6,789
Trade accounts receivable		74,355			78,326
Other receivables		93,380			49,303
Deferred tax assets		1,409			5,582
Prepaid expenses		1,800			3,179

Total current assets		178,992			143,179

Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties		1,450,975			1,189,078
Less accumulated depreciation, depletion and amortization		(554,111	)		(418,347	)

Net property and equipment		896,864			770,731

Other assets		12,608			13,284
Deferred financing costs — net of accumulated amortization of $5,873 in 2006 and $5,169 in 2005		4,143			4,091

	$	1,092,607		$	931,285

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	54,090		$	28,810
Accrued expenses		136,852			108,087
Fair value of commodity derivative instruments		1,613			9,875
Current maturities of long-term debt		—			109

Total current liabilities		192,555			146,881

Long-term debt		320,000			235,000
Deferred tax liabilities		91,154			87,559
Asset retirement obligation		65,603			56,039
Other		2,641			11,213

		671,953			536,692

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: 2006 – 41,929,748 shares; 2005 – 41,468,093 shares		420			415
Additional paid-in capital		361,942			348,863
Accumulated other comprehensive loss — net of deferred taxes of $1,001 in 2006 and $7,098 in 2005		(1,780	)		(12,619	)
Retained earnings		117,512			115,366
Treasury stock, at cost. 2006 — 3,479,814 shares; 2005 — 3,474,208 shares		(57,440	)		(57,432	)

Total stockholders’ equity		420,654			394,593
Commitments and contingencies

	$	1,092,607		$	931,285

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,
	2006			2005			2006			2005
Revenue:
Oil and natural gas	$	107,390		$	91,977		$	337,594		$	295,660
Other		101			72			322			344

		107,491			92,049			337,916			296,004

Costs and expenses:
Lease operating		15,230			14,163			44,716			40,720
Transportation expense		727			288			1,538			793
Taxes, other than on earnings		5,762			2,836			10,948			8,258
Exploration expenditures, dry hole costs and impairments		12,112			23,313			54,491			52,940
Depreciation, depletion and amortization		45,639			26,278			142,416			79,430
General and administrative		68,457			10,221			93,194			30,283
Other expense		667			—			2,544			321

Total costs and expenses		148,594			77,099			349,847			212,745

Business interuption recovery		8,293			—			31,576			—
Income (loss) from operations		(32,810	)		14,950			19,645			83,259

Other income (expense):
Interest income		328			223			1,080			518
Interest expense		(6,907	)		(4,929	)		(17,190	)		(13,312	)

		(6,579	)		(4,706	)		(16,110	)		(12,794	)

Income (loss) before income taxes		(39,389	)		10,244			3,535			70,465
Income taxes		14,147			(3,724	)		(1,389	)		(25,474	)

Net income (loss)		(25,242	)		6,520			2,146			44,991

Less dividends earned on preferred stock and accretion of discount		—			—			—			(944	)

Net income (loss) available to common stockholders	$	(25,242	)	$	6,520		$	2,146		$	44,047

Basic earnings (loss) per share	$	(0.66	)	$	0.17		$	0.06		$	1.20

Diluted earnings (loss) per share	$	(0.66	)	$	0.16		$	0.05		$	1.11

Weighted average common shares used in computing income (loss) per share:
Basic		38,414			37,779			38,254			36,798
Incremental common shares
Preferred stock		—			—			—			727
Stock options		—			846			195			915
Warrants		—			2,077			1,759			1,964
Restricted share units		—			243			262			206
Performance shares		—			—			13			—

Diluted		38,414			40,945			40,483			40,610

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,
	2006			2005
Cash flows from operating activities:
Net income	$	2,146		$	44,991
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		142,416			79,430
Loss on disposition of assets		3,497			92
Non cash-based compensation		7,968			6,267
Deferred income taxes		1,672			25,128
Exploration expenditures		42,108			41,208
Amortization of deferred financing costs		704			746
Other		1,195			674
Changes in operating assets and liabilities:
Trade accounts receivable		3,972			13,587
Other receivables		(44,077	)		(6,822	)
Prepaid expenses		1,379			(2,176	)
Other assets		702			(1,731	)
Accounts payable and accrued expenses		22,576			52,391
Other liabilities		(874	)		(114	)

Net cash provided by operating activities		185,384			253,671

Cash flows used in investing activities:
Acquisition of business, net of cash acquired		(420	)		(863	)
Property acquisitions		(15,408	)		(187,137	)
Exploration and development expenditures		(253,983	)		(189,278	)
Other property and equipment additions		(443	)		(1,389	)

Net cash used in investing activities		(270,254	)		(378,667	)

Cash flows provided by financing activities:
Equity offering costs		—			(87	)
Deferred financing costs		(783	)		(357	)
Repayments of long-term debt		(30,109	)		(53,080	)
Proceeds from long-term debt		115,000			128,000
Exercise of stock options and warrants		2,021			7,994

Net cash provided by financing activities		86,129			82,470

Net increase (decrease) in cash and cash equivalents		1,259			(42,526	)
Cash and cash equivalents at beginning of period		6,789			93,537

Cash and cash equivalents at end of period	$	8,048		$	51,011

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, 2005 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, 2006 and for the three and nine month periods ended September 30, 2006 and 2005 has not been audited. However, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to present fairly the results of operations for the periods presented have been included therein. The results of operations for the first nine months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

(2) STOCK-BASED COMPENSATION

The Company has two stock-award plans, the 2006 Long Term Stock Incentive Plan and the Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors. Prior to January 1, 2006 the Company accounted for its stock-based compensation in accordance with Accounting Principles Board’s Opinion No. 25, “Accounting For Stock Issued to Employees” (Opinion No. 25) and related interpretations, as permitted by Statement of Financial Accounting Standards No. 123, “Accounting For Stock-Based Compensation” (Statement 123) and Statement of Financial Accounting Standards No. 148, “Accounting For Stock-Based Compensation – Transition and Disclosure,” (Statement 148). Accordingly, compensation expense for a stock option grant was recognized only if the exercise price was less than the fair market value of the Company’s common stock on the grant date.

Effective January 1, 2006, the company adopted the fair-value recognition provisions of Statement of Financial Standards No. 123 (R), “Share Based Payment” (Statement 123(R)), using the modified prospective transition method. Under this method, stock-based compensation expense for the three and nine months ended September 30, 2006 includes:

•

compensation expense for all stock-based compensation awards granted prior to January 1, 2006, but not yet vested, based on the grant-date fair-value estimated in accordance with the original provisions of Statement 123, and

•

compensation expense for all stock-based compensation awards granted subsequent to January 1, 2006, based on the grant-date fair-value estimated in accordance with the provisions of Statement 123(R).

Prior to the adoption of Statement No. 123(R), the Company reported all tax benefits resulting from the exercise of stock options as operating cash flows in its consolidated statements of cash flows. In accordance with Statement 123(R), the Company is now required to report the excess tax benefits from the exercise of stock options as financing cash flows. For the three and nine months ended September 30, 2006, no excess tax benefits were reported in the statement of cash flows as the Company is in a net operating loss carryforward position.

The Company has a long term-incentive plan authorizing various types of market and performance based incentive awards which may be granted to officers and employees. The 2006 Long Term Stock Incentive Plan (the Employee Plan) provides for the grant of stock options for which the exercise price, set at the time of the grant, is not less than the fair market value per share at the date of grant. The outstanding options have a term of 10 years and generally vest over 3 years with a limited group of grants that cliff vest at the end of 5 years. The Employee Plan also provides for restricted stock and restricted share units, which are referred to as non-vested share awards under Statement 123(R), and performance share awards. The Employee Plan was adopted by the board of directors in March 2006 and approved by stockholders in May 2006 and is administered by the Compensation Committee of the board of directors or such other committee as may be designated by the board of directors. The Compensation Committee is authorized to select the employees of the Company and its subsidiaries and affiliates who will receive awards, to determine the types of awards to be granted to each person, and to establish the terms of each award. The total number of shares that may be issued under the plan for all types of awards was 2,604,414 as of May 2006.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

The Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors (the Director Plan) was adopted by the board of directors in March 2005 and approved by our stockholders in May 2005. The Director Plan permits the use of restricted share units in addition to stock options to provide flexibility to adjust grants to maintain a competitive equity component for non-employee directors. The number of shares authorized for issuance under the Director Plan is 500,000. The size of any grants of stock options and restricted share units to non-employee directors, including to new directors, will be determined annually, based on the analysis of an independent compensation consultant. The option exercise price for an option granted under the Director Plan shall be the fair market value of the shares covered by the option at the time the option is granted. Options become fully exercisable on the first anniversary of the date of the grant. Prior to the one-year anniversary, the options shall be exercisable as to a number of shares covered by the option determined by pro-rating the number of shares covered by the option based on the number of days elapsed since the date of the grant. Any portion of an option that has not become exercisable prior to the cessation of the optionee’s service as a director for any reason shall not thereafter become exercisable. Each option shall expire on the earlier of (i) ten (10) years from the date of the granting thereof, or (ii) thirty-six (36) months after the date the optionee ceases to be a director of the Company for any reason. Each restricted share unit represents the right to receive one share of Common Stock upon the earlier to occur of: (i) the cessation of the eligible director’s service as a director of the Company for any reason, or (ii) the occurrence of a change of control of the Company. An eligible director shall become 100% vested in a grant of restricted share units on the first anniversary of the date of grant. Prior to the first anniversary of the grant, an eligible director shall be vested in a number of restricted share units determined by pro-rating the grant based on the number of days elapsed since the date of the grant. If the service of an eligible director ceases for any reason prior to the first anniversary of the grant, other than in connection with the occurrence of a change of control of the Company, the director shall forfeit any unvested restricted share units.

During the three month period ended September 30, 2006, the Company recognized compensation expense of $1.1 million for option shares, $1.5 million for non-vested share awards and $0.5 million for performance share awards. Of the $1.1 million option expense included in the Company’s statements of operations for the quarter ended September 30, 2006, $0.5 million relates to awards granted prior to January 1, 2006. The deferred income tax benefit recognized during that same period for the awards was $1.1 million. During the three month period ended September 30, 2005, the Company did not recognize any compensation expense for option shares and recognized $1.3 million for non-vested share awards and $1.1 million for performance share awards. Total deferred income tax benefit recognized during that same period for share awards was $0.9 million.

During the nine month period ended September 30, 2006, the Company recognized compensation expense of $3.2 million for option shares, $4.2 million for non-vested share awards and $0.4 million for performance share awards. Of the $3.2 million option expense included in the Company’s statements of operations for the nine months ended September 30, 2006, $2.0 million relates to awards granted prior to January 1, 2006. The deferred income tax benefit recognized during that same period for the awards was $2.8 million. During the nine month period ended September 30, 2005, the Company recognized $0.7 million of compensation expense for option shares due to the modification of an award under Opinion No. 25, and recognized $3.3 million for non-vested share awards and $2.1 million for performance share awards. Total deferred income tax benefit recognized during that same period for share awards was $2.2 million.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

The following table illustrates the pro forma effect on net income and earnings per common share for the three and nine month periods ended September 30, 2005 as if the Company had applied the fair value method to measure stock-based compensation, as required under the disclosure provisions of Statement 123(R):


	Three Months Ended September 30, 2005			Nine Months Ended September 30, 2005
	(in thousands, except per share amounts)
Net income available to common stockholders:
As reported	$	6,520		$	44,047
Less: Pro forma net stock-based employee compensation cost, after tax		(485	)		(655	)

Pro forma	$	6,035		$	43,392

Basic earnings per share:
As reported	$	0.17		$	1.20
Pro forma	$	0.16		$	1.18
Diluted earnings per share:
As reported	$	0.16		$	1.11
Pro forma	$	0.15		$	1.09
Stock-option-based employee compensation cost, net of tax, included in net income as reported	$	—		$	468

The fair value of each share option award is estimated on the date of grant using the Black-Scholes option valuation model with the following weighted average assumptions for the three and nine month periods ended September 30, 2006 and 2005:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Black-Scholes option pricing model assumptions:
Risk free interest rate	4.4	%	4.5	%	4.4	%	4.5	%
Expected life (years)	4.79		5.00		4.79		5.00
Expected volatility	43	%	42	%	43	%	42	%
Dividend yield	—		—		—		—

Expected volatility is based on the historical volatility of the Company’s stock over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time with consideration of expected term of unvested options. The Company has not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. The risk-free interest rate is based on the interest rate on constant maturity bonds published by the Federal Reserve with a maturity commensurate with the expected term of the options granted.

Additionally, Statement 123 (R) requires the Company to estimate pre-vesting option forfeitures at the time of grant and periodically revise those estimates in subsequent periods if actual forfeitures differ from those estimates. The Company records stock-based compensation expense only for those awards expected to vest using an estimated forfeiture rate based on its historical pre-vesting forfeiture data. The Company did estimate forfeitures for the pro forma disclosure provisions of Statement 123 for periods prior to 2006.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

A summary of option share activity for the nine months ended September 30, 2006 is as follows:


	Options		Weighted- Average Exercise Price Per Share		Weighted- Average Remaining Contractual Terms (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding on January 1, 2006	1,828,109		$	16.13
Granted	544,181			21.69
Exercised	(21,666	)		9.06
Forfeited/Cancelled	(191,007	)		25.41

Outstanding on September 30, 2006	2,159,617		$	16.78	7.42	$	36,249
Exercisable on September 30, 2006	1,226,545		$	12.13	6.13	$	14,881

The weighted-average grant-date fair value of option shares granted during the three month periods ended September 30, 2006 and 2005 was $7.84 and $4.14, respectively. The weighted-average grant-date fair value of option shares granted during the nine month periods ended September 30, 2006 and 2005 was $9.24 and $6.86, respectively. The aggregate intrinsic value of option shares (the amount by which the market price of the stock on the date of exercise exceeded the market price of the stock on the date of grant) exercised during the three months ended September 30, 2006 and 2005 was $0.3 million and $5.7 million, respectively. The aggregate intrinsic value of option shares exercised during the nine months ended September 30, 2006 and 2005 was $0.3 million and $12.6 million, respectively. The following table summarizes information about option shares outstanding at September 30, 2006:


Range of Exercise Prices	Shares	Options Outstanding			Options Exercisable
Range of Exercise Prices	Shares	Remaining Contractual Life	Weighted Average Price		Shares	Weighted Average Price
$7.00 – $14.00	1,092,043	6.1 years	$	10.88	1,040,143	$	10.75
$14.01 – $21.00	307,318	8.2 years	$	17.48	92,767	$	15.70
$21.01 – $28.00	760,256	9.0 years	$	24.98	93,635	$	23.95

The fair value of non-vested share awards equals the market value of the underlying stock on the date of grant. The weighted-average grant-date fair value of the non-vested share awards granted during the three month periods ended September 30, 2006 and 2005 was $18.16 per share and $26.59 per share, respectively. The weighted-average grant-date fair value of the non-vested share awards granted during the nine month periods ended September 30, 2006 and 2005 was $21.62 per share and $26.50 per share, respectively. The total fair value of non-vested share awards that vested during the three month period ended September 30, 2006 was insignificant and was $0.4 million during the three month period ended September 30, 2005. The total fair value of non-vested share awards that vested during each of the nine month periods ended September 30, 2006 and 2005 was $2.8 million and $3.1 million, respectively. A summary of the status of the Company’s non-vested share awards as of September 30, 2006 and changes during the nine month period ended September 30, 2006 is as follows:


	Shares		Weighted- Average Grant-Date Fair Value
Non-vested share awards outstanding at January 1, 2006	656,629		$	23.08
Granted	268,722			21.62
Vested	(116,895	)		19.08
Forfeited/Cancelled	(64,112	)		23.81

Non-vested share awards outstanding at September 30, 2006	744,344		$	23.54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

During the period from 2003 through 2005, performance shares were awarded to officers and key employees with the number of shares to be issued upon being earned, at the end of their respective three year cycles, being based on certain performance measures. The shares awarded can range from a minimum of 0% to a maximum of 200% of the target number of shares depending on the level at which the goals are attained. The Company has not awarded any performance shares in 2006. In the nine month period ended September 30, 2006, 55,111 shares were earned and issued and 35,756 shares expired unearned or were forfeited leaving 331,190 shares reserved based on the maximum award available, of which 69,000 shares are considered probable of being earned as of September 30, 2006.

As of September 30, 2006, there was $5.9 million of total unrecognized compensation expense related to option shares granted which is expected to be recognized over a weighted-average period of 2.0 years. As of September 30, 2006, there was $9.3 million of total unrecognized compensation expense related to non-vested share awards granted which is expected to be recognized over a weighted-average period of 2.3 years and as of September 30, 2006, there was $1.0 million of total unrecognized compensation expense related to performance shares granted which is expected to be recognized over a weighted-average period of 1.0 years.

(3) MERGERS AND ACQUISITIONS

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 and was included in other assets in the Consolidated Balance Sheet. On August 28, 2006, Woodside Petroleum, Ltd. (Woodside) announced its intention to commence a 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 tender offer was commenced on August 31, 2006 and was effective until September 28, 2006. On September 14, 2006, the Company announced that, on September 13, 2006, the Company’s board of directors (the Board) rejected as inadequate the unsolicited conditional offer by Woodside and recommended that its stockholders not tender their shares. Woodside extended its offer three times and announced on October 26, 2006 that it was extending its offer for the final time until November 17, 2006. 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 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 will be 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 the third quarter of 2006 along with $3.0 million of other Stone merger related costs.

On March 8, 2005, the Company closed the acquisition of the remaining 50% working interest in South Timbalier 26 above approximately 13,000 feet subsea that it did not already own for approximately $19.6 million after closing adjustments from the effective date of December 1, 2004. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. As a result of the acquisition, the Company now owns a 100% working interest in the producing horizons in this field. The acquisition expands the Company’s interest in its core Greater Bay Marchand area and gives the Company additional flexibility in undertaking the future development of the South Timbalier 26 field.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

On January 20, 2005, the Company closed an acquisition of properties and reserves in south Louisiana for approximately $149.6 million in cash, after adjustments for the exercise of preferential rights by third parties and closing adjustments. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. The acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells, with estimated acquisition date proved reserves of 51.2 billion cubic feet equivalent. Also included were interests in 22 exploratory prospects. The transaction increased the Company’s exploration opportunities in its expanded focus area and further reduced the concentration of its reserves and production. In connection with the acquisition, the Company also entered into a two-year agreement with the seller of the properties that defines an area of mutual interest (AMI) encompassing over one million acres. The proved reserves, prospects and AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

The Company has included the results of operations from the consummated acquisitions discussed above from their respective closing dates.

In connection with an acquisition in 2002, the Company issued among other things, 383,707 shares of newly authorized and issued Series D Exchangeable Convertible Preferred Stock (the Series D Preferred Stock), with a $38.4 million liquidation preference and an issue date fair value of $34.7 million discounted to give effect to the increasing dividend rate. On February 28, 2005, the Company gave notice of the redemption of all of the Series D Preferred Stock issued in connection with the acquisition that remained outstanding on the redemption date of March 21, 2005. The redemption price was $100 per share plus accrued and unpaid dividends to the redemption date. Holders of the Series D Preferred Stock had the right to convert their shares into shares of common stock through the close of business on March 18, 2005. All holders exercised their right to convert their shares and there were no preferred shares outstanding as of the close of business on March 18, 2005.

The Company also issued warrants to purchase four million shares of the Company’s common stock in the same acquisition. Of the warrants, one million had a strike price of $9.00 and three million had a strike price of $11.00 per share. The warrants became exercisable on January 15, 2003 and expire on January 15, 2007. At September 30, 2006 there were 677,796 warrants outstanding with a strike price of $9.00 per share and 2,349,549 warrants outstanding with a strike price of $11.00 per share.

In addition, former preferred stockholders of the acquired company have the right to receive contingent consideration based upon a percentage of the amount by which the before tax net present value of proved reserves related, in general, to exploratory prospect acreage held by the acquired company as of the closing date of the acquisition (the Ring-Fenced Properties) exceeds the net present value discounted at 30%. The potential consideration is determined annually from March 3, 2003 until March 1, 2007. The cumulative percentage remitted to the participants was 20% for the March 3, 2003, 30% for the March 1, 2004, 35% for the March 1, 2005 and 40% for the March 1, 2006 determination dates and is 50% for the March 1, 2007 determination date. The contingent consideration, if any, may be paid in the Company’s common stock or cash at the Company’s option (with a minimum of 20% in cash) and in no event will exceed a value of $50 million. In the first three months of 2006 and 2005, the Company capitalized, as additional purchase price, and paid additional consideration in cash, of $0.4 million and $0.9 million related to the March 1, 2006 and the March 1, 2005 contingent consideration determination dates, respectively. Due to the uncertainty inherent in estimating the value of future contingent consideration which includes annual revaluations based upon, among other things, drilling results from the date of the prior revaluation, and development, operating and abandonment costs and production revenues (actual historical and future projected, as contractually defined, as of each revaluation date) for the Ring-Fenced Properties, total final consideration will not be determined until March 1, 2007. All additional contingent consideration will be capitalized as additional purchase price.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

(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 conversion of convertible preferred stock shares, and 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. The diluted loss per share calculation for the three months ended September 30, 2006 produces results that are anti-dilutive, therefore, the diluted loss per share amount as reported for that period in Consolidated Statement of Operations are the same as the basic loss per share amount.

(5) HEDGING ACTIVITIES

The Company enters into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of oil and natural gas. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded in other revenue, whereas gains and losses from the settlement of hedging contracts are recorded in oil and natural gas revenue. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. Natural gas hedges are settled based on the average of the last three days of trading of the NYMEX Henry Hub natural gas contract for each month.

From time to time the Company uses financially-settled crude oil and natural gas swaps and zero-cost collars to provide floor prices with varying upside price participation. With a financially-settled swap, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the hedged price for the transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar.

The Company had the following hedging contracts as of September 30, 2006:

Natural Gas Positions


			Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Daily	Total
10/06 – 12/06	Collar	$5.00/$9.51	15,000	1,380,000
01/07 – 12/07	Collar	$5.00/$8.00	10,000	3,650,000

Settlements of hedging contracts did not impact crude oil revenues in the three and nine month periods ended September 30, 2006, respectively and reduced natural gas revenues by $0 and $1.0 million in the three and nine month periods ended September 30, 2006, respectively. The Company has not discontinued hedge accounting treatment in the periods presented.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

The following tables reconcile the change in accumulated other comprehensive income for the nine month period ending September 30, 2006 and 2005.


	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	)


	Nine Months Ended September 30, 2005
	(in thousands)
Accumulated other comprehensive loss as of December 31, 2004 — net of taxes of $630				$	(1,119	)
Net income	$	44,991
Other comprehensive loss — net of tax
Hedging activities
Reclassification adjustments for settled contracts — net of taxes of $(2,278)		4,049
Changes in fair value of outstanding hedging positions — net of taxes of $15,375		(27,332	)

Total other comprehensive loss		(23,283	)		(23,283	)

Comprehensive income	$	21,708

Accumulated other comprehensive loss as of September 30, 2005 — net of taxes of $13,726				$	(24,402	)

Based upon current prices, the Company expects to transfer approximately $1.6 million of pretax net deferred losses in accumulated other comprehensive loss as of September 30, 2006 to earnings during the next twelve months when the forecasted transactions actually occur.

(6) OIL AND GAS PROPERTIES

Effective July 1, 2005, the Company adopted Financial Accounting Standards Board Staff Position FAS 19-1 “Accounting for Suspended Well Costs” (FSP 19-1). FSP 19-1 amended Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (Statement 19) to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company has not and currently does not have any exploratory well costs that have been capitalized for a period greater than one year for which proved reserves have not been booked.

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, 2006.


	Nine Months Ended September 30, 2006
	(in thousands)
December 31, 2005	$	56,039
Accretion expense		3,250
Revisions		2,151
Liabilities incurred		5,023
Liabilities settled		(860	)

September 30, 2006	$	65,603

(8) INDEBTEDNESS

On June 2, 2006, the Company amended and extended to May 2011 its bank credit facility and increased its borrowing base from $150 million to $225 million. Modifications to the bank credit facility include, among other things, the expansion of the revolving credit facility to $300 million from $200 million (subject to borrowing base limitations) and improved grid pricing for interest rate margins and commitment fees. In addition, under the amended bank credit facility, the Company has the ability to increase availability under the revolver to $400 million, subject to borrowing base limitations. At September 30, 2006, the Company had $170.0 million outstanding under the bank credit facility and $55.0 million available under its then current borrowing base of $225 million. The Company pays an annual fee on the unused portion of the facility ranging between 0.30% 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 in the bank credit facility agreement, of 1.0x and (ii) maintain a minimum EBITDAX to interest ratio, as defined in the bank credit facility agreement, of 3.5x. The Company was in compliance with the bank credit facility covenants as of September 30, 2006. 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 August 5, 2003, the Company issued $150 million of 8.75% Senior Notes Due 2010 (the Senior Notes) in a Rule 144A private offering (the Debt Offering) which allows unregistered transactions with qualified institutional buyers. In October 2003, the Company consummated an exchange offer pursuant to which it exchanged registered Senior Notes (the Registered Senior Notes) having substantially identical terms as the Senior Notes for the privately placed Senior Notes. After discounts and commissions and estimated offering expenses, the Company received $145.3 million, which was used to redeem all of the outstanding 11% Senior Subordinated Notes Due 2009, that had been issued in connection with a business combination in 2002, and to repay substantially all of the borrowings outstanding under the Company’s bank credit facility. In January 2005, the remainder of the net proceeds were used to purchase properties in south Louisiana as discussed in note (3).

The Registered Senior Notes mature on August 1, 2010 with interest payable each February 1 and August 1. The indenture relating to the Registered Senior Notes contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on its common stock, make investments, create liens on its assets, engage in transactions with its affiliates, transfer or sell assets and consolidate or merge substantially all of its assets. The Registered Senior Notes are not subject to any sinking fund requirements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

(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. General and administrative costs associated with moving offices as well as relocation allowances paid to employees approximated $1.6 million during 2005.

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. Recovery of lost revenue for the East Bay field and two other fields began accruing in October 2005 and recovery on a fourth field began accruing in November 2005. Recovery ceased for three of the fields in 2005, but continued at the East Bay field until October 2006. Through September 30, 2006, the total business interruption claim on these fields was $52.1 million, of which $24.7 million had not been collected as of September 30, 2006 and is recorded in other receivables on the Company’s Consolidated Balance Sheet. As of November 2, 2006, an additional $11.0 million of this amount had been collected. Total offshore repair costs incurred as of September 30, 2006, subject to insurance recoveries in excess of applicable deductibles and uninsured repair costs, for Hurricanes Katrina, Rita and Cindy, were $75.9 million of which $67.4 million is recorded in other receivables on the Company’s consolidated balance sheet net of collections as of September 30, 2006 of $8.5 million. As of November 2, 2006, an additional $12.5 million of this amount had been collected.

(10) NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153 “Exchanges of Non-monetary assets — an amendment of APB Opinion No. 29” (Statement 153). Statement 153 amends Accounting Principles Board (APB) Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. A non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement 153 does not apply to a pooling of assets in a joint undertaking intended to fund, develop, or produce oil or natural gas from a particular property or group of properties. The provisions of Statement 153 are effective for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early adoption was permitted and the provisions of Statement 153 should be applied prospectively. The Company has adopted the provisions of Statement 153 and it did not have an impact on the financial position, results of operations or cash flows of the Company.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” (Statement 154). Statement 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to Statement 154. The provisions of Statement 154 shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company has assessed the impact of Statement 154 which did not have an impact on the Company’s financial position, results of operations or cash flows.

In February 2006, the FASB issued Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140” (Statement 155). Among other changes, Statement 155 eliminates the exemption from applying FASB Statement No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. Statement 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company has assessed the impact of Statement 155 which will not have an impact on the Company’s financial position, results of operations or cash flows.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

In March 2006, the FASB issued Statement of Financial Accounting Standards No. 156, “Accounting for Servicing of Financial Assets — an amendment of FASB Statement No. 140” (Statement 156). Among other changes, Statement 156 requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. Statement 156 is effective for all fiscal years beginning after September 15, 2006. The Company has assessed the impact of Statement 156 which will not have an impact on the Company’s financial position, results of operations or cash flows.

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. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is assessing the impact of FIN 48 which is not expected to have an impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurments” (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 assessing the impact of Statement 157 which is not expected to have an impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (Statement 158). Statement 158 improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. Statement 158 also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. An employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Statement 158 will not have an impact on the Company’s financial position, results of operations or cash flows.

(11) 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 terminated Stone merger agreement, for which it received a fee of $0.5 million in the second quarter, and has provided and will continue to provide services in connection with the Woodside offer and the Company’s exploration of strategic alternatives. The Company incurred $1.6 million for these services related to the Woodside tender offer in the third quarter and inclusive of $0.6 million accrued in the third quarter has committed to an additional $7.0 million due to Evercore upon the earlier of the consummation of a transaction or September 5, 2007.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

(12) SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

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

Supplemental Condensed Consolidating Balance Sheet

As of September 30, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	8,048		$	—		$	—		$	8,048
Accounts receivable		170,838			(3,103	)		—			167,735
Other current assets		3,146			63			—			3,209

Total current assets		182,032			(3,040	)		—			178,992
Property and equipment		1,009,910			441,065			—			1,450,975
Less accumulated depreciation, depletion and amortization		(377,856	)		(176,255	)		—			(554,111	)

Net property and equipment		632,054			264,810			—			896,864
Investment in affiliates		219,365			890			(220,255	)		—
Notes receivable, long-term		—			216,370			(216,370	)		—
Other assets		16,772			(21	)		—			16,751

	$	1,050,223		$	479,009		$	(436,625	)	$	1,092,607

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	188,416		$	2,526		$	—		$	190,942
Fair value of commodity derivative instruments		1,613			—			—			1,613

Total current liabilities		190,029			2,526			—			192,555
Long-term debt		320,000			216,370			(216,370	)		320,000
Other liabilities		119,540			39,858			—			159,398

		629,569			258,754			(216,370	)		671,953
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		420			98			(98	)		420
Additional paid-in capital		361,942			1,683			(1,683	)		361,942
Accumulated other comprehensive loss		(1,780	)		—			—			(1,780	)
Retained earnings		117,512			218,471			(218,471	)		117,512
Treasury stock		(57,440	)		—			—			(57,440	)

Total stockholders’ equity		420,654			220,255			(220,255	)		420,654

	$	1,050,223		$	479,009		$	(436,625	)	$	1,092,607

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

Supplemental Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenue:
Oil and natural gas	$	219,890		$	117,704		$	—		$	337,594
Other		(9,113	)		168			9,267			322

		210,777			117,872			9,267			337,916

Costs and expenses:
Lease operating		5,205			41,049			—			46,254
Taxes, other than on earnings		1,430			9,518			—			10,948
Exploration expenditures		42,032			12,459			—			54,491
Depreciation, depletion and amortization		79,019			63,397			—			142,416
General and administrative		92,479			11,965			(11,250	)		93,194
Other expense		2,544			—			—			2,544

Total costs and expenses		222,709			138,388			(11,250	)		349,847
Business interruption recovery		31,576			—			—			31,576
Income from operations		19,644			(20,516	)		20,517			19,645

Interest expense, net		(16,109	)		(1	)		—			(16,110	)

Income before income taxes		3,535			(20,517	)		20,517			3,535
Income taxes		(1,389	)		—			—			(1,389	)

Net income	$	2,146		$	(20,517	)	$	20,517		$	2,146

Supplemental Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)
Net cash provided by operating activities	$	149,184		$	36,200		$	—	$	185,384
Cash flows used in investing activities:
Acquisition of business, net of cash acquired		(420	)		—			—		(420	)
Property acquisitions		(15,408	)		—			—		(15,408	)
Exploration and development expenditures		(217,892	)		(36,091	)		—		(253,983	)
Other property and equipment additions		(443	)		—			—		(443	)

Net cash used in investing activities		(234,163	)		(36,091	)		—		(270,254	)

Cash flows used in financing activities:
Repayments of long-term debt		(30,000	)		(109	)		—		(30,109	)
Proceeds from long-term debt		115,000			—			—		115,000
Deferred financing costs		(783	)		—			—		(783	)
Exercise of stock options and warrants		2,021			—			—		2,021

Net cash provided by financing activities		86,238			(109	)		—		86,129

Net increase in cash and cash equivalents		1,259			—			—		1,259
Cash and cash equivalents at beginning of period		6,789			—			—		6,789

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(UNAUDITED)

(13) CONTINGENCIES

On August 28, 2006, Woodside commenced an action against the Company, the Company’s directors, and Stone in the Delaware Court of Chancery for New Castle County (the Delaware Court) styled as ATS, Inc. v. Bachmann et al., C.A. No. 2374-N (the Woodside Litigation). As amended on October 19, 2006, the Woodside complaint alleged that the termination fee provisions in the Merger Agreement were invalid under Delaware law. Woodside also alleged that the fee the Company paid Stone in connection with the termination of the Merger Agreement and Stone’s termination of its merger agreement with Plains constituted an invalid penalty under Delaware law. Woodside asserted that, absent the invalidation of the termination fee payments, the Company’s shareholders will be unable to make a fully informed choice as to whether to accept the Tender Offer. Woodside sought declaratory and injunctive relief.

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 alleges 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 alleges that the Company’s directors have failed to adequately disclose material information relevant to the Company stockholders’ decision whether to accept the Tender Offer. Farrington seeks declaratory and injunctive relief as well as unspecified damages.

On October 19, 2006, the Delaware Court denied motions filed by Woodside and Farrington seeking expedited consideration of these claims. The Company and the individual defendants believe the claims are without merit and intend to defend vigorously against those claims.

On October 26, 2006, Woodside dismissed its legal action without prejudice.

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.

(14) RECLASSIFICATIONS

Certain reclassifications have been made to the prior period financial statements in order to conform to the classification adopted for reporting in fiscal 2006.

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.

While the impacts of Hurricanes Katrina, Rita, Cindy, Dennis and Emily (the “Tropical Weather”) were significant in 2005 and continued to affect us into 2006, we have continued to make progress toward implementing our long-term growth strategy to increase our oil and natural gas reserves and production while keeping our finding and development costs and operating costs competitive with our industry peers. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential and by making acquisitions, including acquisitions in our core focus area which includes the Gulf of Mexico Shelf and onshore Gulf Coast regions and, as a result of an acquisition of acreage in 2006, the deepwater Gulf of Mexico. We also evaluate acquisition opportunities outside of our core focus area as a complement to the exploration and development activities we have budgeted for that area. Our drilling program contains some higher risk, higher reserve potential opportunities as well as some lower risk, lower reserve potential opportunities, in order to achieve a balanced program of reserve and production growth.

We use the successful efforts method of accounting for our investment in oil and natural gas properties. Under this method, we capitalize lease acquisition costs, costs to drill and complete exploration wells in which proven reserves are discovered and costs to drill and complete development wells. Exploratory drilling costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. Seismic, geological and geophysical and delay rental expenditures are expensed as they are incurred. We conduct many of our exploration and development activities jointly with others and, accordingly, recorded amounts for our oil and natural gas properties reflect only our proportionate interest in such activities. Our annual report on Form 10-K for the fiscal year ended December 31, 2005, includes a discussion of our critical accounting policies, which have not changed significantly since the end of the fiscal year.

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, 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 tender offer was commenced on August 31, 2006 and was effective until September 28, 2006. On September 14, 2006, we announced that, on September 13, 2006, our board of directors (the “Board”) rejected as inadequate the unsolicited conditional offer by Woodside and recommended that our stockholders not tender their shares. Woodside extended its offer three times and announced on October 26, 2006 that it was extending its offer for the final time until November 17, 2006. 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. In conjunction with the termination of the Merger Agreement, we paid $8.0 million to Stone, which will be 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 the third quarter of 2006 along with other merger related costs of $3.0 million. We expect to incur legal and financial advisor fees in the future related to the shareholder litigation as well as the Woodside tender offer and our exploration of potential strategic alternatives.

On June 2, 2006, we amended and extended to May 2011 our bank credit facility and increased our borrowing base from $150 million to $225 million. Modifications to the bank credit facility include, among other things, the expansion of the revolving credit facility to $300 million from $200 million (subject to borrowing base limitations) and improved grid pricing for interest rate margins and commitment fees. In addition, under the amended bank credit facility, we have the ability to increase availability under the revolver to $400 million, subject to borrowing base limitations. At September 30, 2006, we had $170 million outstanding under the bank credit facility. The borrowing base remains subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility.

On August 29, 2005, Hurricane Katrina made landfall in the United States south of New Orleans causing catastrophic damage throughout portions the Gulf of Mexico and to portions of Alabama, Louisiana and Mississippi, including New Orleans. As a result of the devastating effects of the storm on New Orleans and surrounding areas, we announced on August 30 that we had elected to establish temporary headquarters at our Houston, Texas office. A satellite office was also established in Baton Rouge, Louisiana. On September 24, 2005, Hurricane Rita made landfall in the United States on the Texas/Louisiana border. 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 other Tropical Weather, nearly all of our production was shut in at one time or another during the third quarter of 2005. During 2005 we maintained business interruption insurance on our significant properties, including our East Bay field. Recovery of lost revenue for our East Bay field and three other fields began accruing at various dates in 2005 as a result of the Tropical Weather and by the end of October 2006 had ceased accruing on all fields. Through September 30, 2006, we had recorded $52.1 million for business interruption recoveries of which $31.6 million and $20.6 million were recorded in the statement of operations in 2006 and fourth quarter of 2005, respectively.

On March 8, 2005, we closed the acquisition of the remaining 50% working interest in South Timbalier 26 above approximately 13,000 feet subsea that we did not already own for approximately $19.6 million after closing adjustments from the effective date of December 1, 2004. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. As a result of the acquisition, we now own a 100% working interest in the producing horizons in this field. The acquisition expands our interest in our core Greater Bay Marchand area and gives us additional flexibility in undertaking the future development of the South Timbalier 26 field.

On January 20, 2005, we closed an acquisition of properties and reserves in south Louisiana for $149.6 million in cash, after adjustments for the exercise of preferential rights by third parties and closing adjustments. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. The acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells, with estimated acquisition date proved reserves of 51.2 billion cubic feet equivalent. Also included were interests in 22 exploratory prospects. The transaction increased the exploration opportunities in our expanded focus area and further reduced the concentration of our reserves and production. In connection with the acquisition, we also entered into a two-year agreement with the seller of the properties that defined an area of mutual interest (“AMI”) encompassing over one million acres. The proved reserves, prospects and the AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

We have included the results of operations from the 2005 acquisitions discussed above from their respective closing dates.

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. We believe the near term may provide us with opportunities to acquire targeted properties, including those within our focus area. In the second and third quarters of this fiscal year, we have drawn on our bank credit facility to fund costs associated with both the termination of the Stone Merger Agreement and financial advisory and legal fees associated with the Woodside offer as well as costs related to our outstanding Tropical Weather related insurance claims.

RESULTS OF OPERATIONS

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

REVENUES AND NET INCOME


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Net production (per day):
Oil (Bbls)		8,092			6,642			7,824			9,017
Natural gas (Mcf)		103,975			75,899			106,162			90,596
Total barrels of oil equivalent (Boe)		25,421			19,292			25,518			24,116
Oil and natural gas revenues (in thousands):
Oil	$	48,814		$	30,279		$	133,048		$	114,935
Natural gas		58,576			61,698			204,546			180,725
Total		107,390			91,977			337,594			295,660
Average sales prices, net of hedging:
Oil (per Bbl)	$	65.57		$	49.55		$	62.29		$	46.69
Natural gas (per Mcf)		6.12			8.84			7.06			7.31
Total (per Boe)		45.92			51.82			48.46			44.91
Impact of hedging:
Oil (per Bbl)	$	—		$	(5.76	)	$	—		$	(2.53	)
Natural gas (per Mcf)		—			(0.01	)		(0.03	)		—
Average costs (per Boe):
Lease operating expense	$	6.51		$	7.98		$	6.42		$	6.19
Taxes, other than on earnings		2.46			1.60			1.57			1.25
Depreciation, depletion and amortization		19.51			14.81			20.44			12.06

Increase in oil and natural gas revenues between periods presented (net of hedging) due to:
Changes in prices of oil	$	9,789					$	38,399
Changes in production volumes of oil		8,746						(20,286	)

Total increase in oil sales		18,535						18,113

Changes in prices of natural gas	$	(18,617	)				$	(6,184	)
Changes in production volumes of natural gas		15,495						30,005

Total increase (decrease) in natural gas sales		(3,122	)					23,821

Our oil and natural gas revenues increased to $107.4 million in the third quarter of 2006 from $92.0 million in the third quarter of 2005. The increase in third quarter of 2006 was a result of production levels restored from Tropical Weather related damage combined with production from new fields whereas the third quarter of 2005 experienced a sharp decline in production due to damage and shut-ins relating to the Tropical Weather. Our oil and natural gas revenues increased to $337.6 million in the first nine months of 2006 from $295.7 million in the first nine months of 2005. The increase in the first nine months of 2006 was a result of an increase in oil prices as well as an increase in natural gas production due to the commencement of production from new fields including our South Timbalier 41 field offset by a decrease in oil production during the quarter and year to date periods. These increases were partially offset by natural reservoir declines.

We recognized a net loss of $25.2 million in the third quarter of 2006 compared to net income of $6.5 million in the third quarter of 2005. We recognized net income of $2.1 million in the first nine months of 2006 compared to net income of $45.0 million in the first nine months of 2005. The decrease in both periods was due to substantially higher general and administrative expenses due to the expensing of costs related to the terminated Stone merger as well as the additional legal and financial advisory costs associated with the unsolicited tender offer by Woodside to acquire all of our outstanding common stock.

OPERATING EXPENSES

Operating expenses during the three and nine month periods ended September 30, 2006 and 2005 were affected by the following:

•

Lease operating expense (LOE) increased to $15.2 million in the third quarter of 2006 compared with $14.2 million in the third quarter of 2005. Although LOE on a dollar basis increased, LOE on a per BOE basis decreased in the third quarter of 2006 compared to the third quarter of 2005. This decrease was primarily a result of a higher than usual LOE per BOE in 2005 due to insurance deductibles combined with lower production in 2005. LOE increased to $44.7 million in the first nine months of 2006 compared to $40.7 million in the first nine months of 2005. The increase in the year to date period is primarily a result of a general increase in the cost of oilfield industry services combined with workover costs and uninsured repairs made during 2006.

•

Taxes, other than on earnings, increased to $5.8 million in the third quarter of 2006 from $2.8 million in the third quarter of 2005. Taxes, other than on earnings, increased to $10.9 million in the first nine months of 2006 from $8.3 million in the first nine months of 2005. These taxes are expected to fluctuate from period to period depending on our production volumes from non-federal leases and the commodity prices received.

•

Exploration expenditures, including dry hole costs, decreased to $12.1 million in the third quarter of 2006 from $23.3 million in the third quarter of 2005. The expense in the third quarter of 2006 is 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. Seismic expenditures in 2006 included those related to seismic on deepwater prospects. The expense in the third quarter of 2005 was comprised of $10.6 million of costs for exploratory wells or portions thereof which were found to be not commercially productive, $9.3 million of proved property impairments at three of our fields which would need significant capital to extend their economic lives and $3.4 million of seismic expenditures and delay rentals.

Exploration expenditures, including dry hole costs, increased to $54.5 million in the first nine months of 2006 from $52.9 million in the first nine months of 2005. The two largest contributors to the expense in 2006 were dry holes at our West Cameron 25 and Denali prospects of approximately $8.5 million and $7.5 million, respectively. The expense in the first nine months of 2006 is 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. The expense in the nine months of 2005 was comprised of $31.2 million of costs for exploratory wells or portions thereof which were found to be not commercially productive, $10.0 million of proved property impairments and $11.7 million for 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 increased to $45.6 million in the third quarter of 2006 from $26.3 million in the third quarter of 2005. The increase was due to increased production volumes, a shift in the production contribution from our various fields as well as reserve revisions taken in several of our onshore properties at the end of 2005. Depreciation, depletion and amortization increased to $142.4 million in the first nine months of 2006 from $79.4 million in the first nine months of 2005. This increase was again due to increased production volumes, a shift in the production contribution from our various fields as well as reserve revisions taken in several of our onshore properties at the end of 2005. Some fields carry a higher depreciation burden than others and fields in which more recent exploration and development activity has taken place are starting to reflect the effect of rising costs of oilfield industry services and capital goods; therefore, changes in the sources of our production will directly impact this expense.

•

General and administrative expenses increased to $68.5 million in the third quarter of 2006 from $10.2 million in the third quarter of 2005. Included in this expense is stock based compensation of $3.1 million and $2.5 million in the third quarter of 2006 and 2005, respectively. General and administrative expenses increased to $93.2 million in the first nine months of 2006 from $30.3 million in the first nine months of 2005. Included in this expense is stock based compensation of $7.7 million and $6.2 million in the first nine months of 2006 and 2005, respectively. The overall increase in both the three and nine month periods was primarily attributable to expensed costs associated with the terminated Stone Merger Agreement of $46.5 million, of which $43.5 million related to the fee advanced by us to Plains on behalf of Stone to terminate their merger agreement which was included in other assets on our June 30, 2006 balance sheet. Also contributing to the increase are legal and financial advisory costs of $8.2 million associated with the unsolicited Woodside offer.

OTHER INCOME AND EXPENSE

Interest expense increased to $6.9 million in the third quarter of 2006 from $4.9 million in the third quarter of 2005. Interest expense increased to $17.2 million in the first nine months of 2006 from $13.3 million in the first nine months of 2005. The increase was a result of an increase in the interest rate as well as the average borrowings under our bank credit facility in the third quarter and first nine months of 2006 compared to the same periods in 2005.

LIQUIDITY AND CAPITAL RESOURCES

The trend of increased revenues we have experienced from 2005 into the first nine months of 2006 has continued to provide strong cash flows from operations which totaled $185.4 million in the first nine months of the year. We intend to fund our exploration and development expenditures from internally generated cash flows, which we define as cash flows from operations before changes in working capital plus total exploration expenditures. Our cash on hand at September 30, 2006 was $8.0 million. Our future internally generated cash flows will depend on our ability to maintain and increase production through our exploratory and development drilling program, as well as the prices we receive for oil and natural gas. However, from time to time, we use our bank credit facility to fund working capital needs. We believe the near term may provide us with opportunities to acquire targeted properties, including those within our focus area. In the second and third quarters of this fiscal year, we have drawn on our bank credit facility to fund costs associated with both the termination of the Stone Merger Agreement and financial advisory and legal fees associated with the Woodside offer as well as costs related to our outstanding Tropical Weather related insurance claims.

Our bank credit facility, as amended on June 2, 2006, consists of a revolving line of credit with a group of banks available though May 2011. The borrowing base under the bank credit facility was increased in connection with this amendment from $150 million to $225 million. It is subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility as set out in the reserve report to be delivered to the banks each April 1 and October 1. The bank credit facility permits both prime rate borrowings and London interbank offered rate (“LIBOR”) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank credit facility. The spread can range from 1.00% to 1.75% above LIBOR and 0% to 0.50% above prime. The borrowing base under the bank credit facility is secured by substantially all of our assets. At November 1, 2006 we had $175 million outstanding and $50 million of credit capacity available under the bank credit facility. In addition, we pay an annual fee on the unused portion of the facility ranging between 0.30% 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 in the bank credit facility agreement, of 1.0x and (ii) maintain a minimum EBITDAX to interest ratio, as defined in the bank credit facility agreement, of 3.5x. We were in compliance with the bank credit facility covenants as of September 30, 2006.

On August 5, 2003, we issued $150 million of our 8.75% senior notes due 2010 which were exchanged in October 2003 for registered 8.75% senior notes due 2010 (the “Senior Notes”) with substantially the same terms. The Senior Notes bear interest at a rate of 8.75% per annum with interest payable semi-annually on February 1 and August 1. We may redeem the Senior Notes at our option, in whole or in part, at any time on or after August 1, 2007 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 4.375% in 2007 to 0% in 2009 and thereafter. The notes are unsecured obligations and rank equal in right of payment to all existing and future senior debt, including the bank credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness. The indenture relating to the Senior Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets and consolidate or merge substantially all of our assets. The Senior Notes are not subject to any sinking fund requirements.

Net cash of $270.3 million used in investing activities in the first nine months of 2006 consisted primarily of oil and natural gas exploration and development expenditures. Dry hole costs resulting from exploration expenditures are excluded from operating cash flows and included in investing activities. During the first nine months of 2006, we completed 21 drilling projects, 16 of which were successful, and 32 recompletion/workover projects, 28 of which were successful. During the first nine months of 2005, we completed 51 drilling projects, 33 of which were successful, and 25 recompletion/workover projects, 20 of which were successful.

Our 2006 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 2006 is approximately

$400 million. We do not budget for acquisitions. During the first nine months of 2006, capital and exploration expenditures were approximately $311.4 million inclusive of a $0.4 million contingent consideration payment resulting from an acquisition during 2002. The level of our capital and exploration expenditure budget is based on many factors, including results of our drilling program, oil and natural gas prices, industry conditions, participation by other working interest owners and the costs and availability of drilling rigs and other oilfield goods and services. Should actual conditions differ materially from expectations, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2006 capital expenditures.

We have experienced and expect to continue to experience substantial working capital requirements, primarily due to our active capital expenditure program. We believe that internally generated cash flows combined with temporary borrowings from 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, 2005 included a discussion of our contractual obligations. There have been no material changes to that disclosure during the first nine months ended September 30, 2006 except that we have entered into six long-term contracts in the ordinary course of business which commit us to spend approximately $12.4 million in the last three months of 2006, $46.6 million in 2007 and $0.5 million in 2008. 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 December 2004, the FASB issued Statement of Financial Accounting Standards No. 153 “Exchanges of Non-monetary assets — an amendment of APB Opinion No. 29” (“Statement 153”). Statement 153 amends Accounting Principles Board (“APB”) Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. A non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement 153 does not apply to a pooling of assets in a joint undertaking intended to fund, develop, or produce oil or natural gas from a particular property or group of properties. The provisions of Statement 153 shall be effective for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early adoption is permitted and the provisions of Statement 153 should be applied prospectively. We have adopted the provisions of Statement 153 and it did not have an impact on our financial position, results of operations or cash flows.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” (“Statement 154”). Statement 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to Statement 154. The provisions of Statement 154 shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We have adopted the provisions of Statement 153 and it did not have an impact on our financial position, results of operations or cash flows.

In February 2006, the FASB issued Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140” (“Statement 155”). Among other changes, Statement 155 eliminates the exemption from applying FASB Statement No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. Statement 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We have assessed the impact of Statement 155 which will not have an impact on our financial position, results of operations or cash flows.

In March 2006, the FASB issued Statement of Financial Accounting Standards No. 156, “Accounting for Servicing of Financial Assets — an amendment of FASB Statement No. 140” (“Statement 156”). Among other changes, Statement 156 requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. Statement 156 is effective for all fiscal years beginning after September 15, 2006. We have assessed the impact of Statement 156 which will not have an impact on our financial position, results of operations or cash flows.

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. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are assessing the impact of FIN 48 which is not expected to have an impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurments” (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 assessing the impact of Statement 157 which is not expected to have an impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (Statement 158). Statement 158 improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. Statement 158 also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. An employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Statement 158 will not have an impact 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 our respective obligations 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);

•

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 this Form 10-Q, of our Annual Report on Form 10-K for the year ended December 31, 2005. 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, 2006, $170.0 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 2006, 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 $0.4 million based on total variable debt outstanding during the period. If market interest rates had averaged 1% lower in the third quarter of 2006, interest expense for the period on variable rate debt would have decreased, and net income before income taxes would have increased by approximately $0.4 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. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.

We use derivative commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of September 30, 2006, we had the following contracts in place:

Natural Gas Positions


			Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Daily	Total
10/06 – 12/06	Collar	$5.00/$9.51	15,000	1,380,000
01/07 – 12/07	Collar	$5.00/$8.00	10,000	3,650,000

Our hedged volume as of September 30, 2006 approximated 8% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at September 30, 2006, we estimate the pre-tax loss would have been $2.8 million.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil and natural gas may have on the fair value of our derivative instruments. At September 30, 2006, the potential change in the fair value of commodity derivative instruments assuming a 10% increase in the underlying commodity price was a $1.8 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 officer, principal 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 officer, principal 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, 2006 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 officer, principal 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 October 26, 2006, Woodside dismissed its legal action without prejudice.

Item 1A. RISK FACTORS

With the exception of the following risk factors, there have been no other changes to our risk factors as presented in our Form 10-K for the year ended December 31, 2005.

Provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

The existence of some provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The provisions in our certificate of incorporation and bylaws that could delay or prevent an unsolicited change in control of our company include:

•

the board of directors’ ability to issue shares of preferred stock and determine the terms of the preferred stock without approval of common stockholders; and

•

a prohibition on the right of stockholders to call meetings and a limitation on the right of stockholders to present proposals or make nominations at stockholder meetings.

In addition, Delaware law imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

No assurances regarding our company’s exploration of strategic alternatives

On October 12, 2006, we announced that our board of directors had directed management, together with our financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of our company. We make no assurances as to whether it will be able to consummate any such alternative. In addition, the exploration of strategic alternatives will involve expense and will require significant time from management that might otherwise have been spent on operating the business.

Item 6. EXHIBITS


Exhibits:
3.5		Bylaws of Energy Partners, Ltd. (incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed September 14, 2006).

4.1		Rights Agreement, dated as of September 14, 2006, between Energy Partners, Ltd. and Mellon Investor Services LLC, as Rights Agent (incorporated by reference to exhibit 4.1 of the Company’s Form 8-A12B filed September 14, 2006).

10.16		Offer Letter of Mr. Timothy Woodall, dated July 11, 2006 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed August 22, 2006).

10.17		Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed September 14, 2006).

10.18		Form of First Amendment to Change of Control Severance Agreement (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed September 14, 2006).

10.19		First Amendment to Energy Partners, Ltd. Change of Control Severance Plan (incorporated by reference to Exhibit 10.3 of the Company’s Form 8-K filed September 14, 2006).

31.1		Rule 13a-14(a)/15d-14(a) Certification of Chairman and Chief Executive Officer of Energy Partners, Ltd.

31.2		Rule 13a-14(a)/15d-14(a) Certification of Executive Vice President and Chief Financial Officer of Energy Partners, Ltd.

32.0		Section 1350 Certifications

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 6, 2006	By:	/s/ Timothy R. Woodall
		Timothy R. Woodall
		Executive Vice President and Chief Financial Officer
		(authorized officer and principal financial officer)

EXHIBIT INDEX


Exhibits:
3.5		Bylaws of Energy Partners, Ltd. (incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed September 14, 2006).

4.1		Rights Agreement, dated as of September 14, 2006, between Energy Partners, Ltd. and Mellon Investor Services LLC, as Rights Agent (incorporated by reference to exhibit 4.1 of the Company’s Form 8-A12B filed September 14, 2006).

10.16		Offer Letter of Mr. Timothy Woodall, dated July 11, 2006 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed August 22, 2006).

10.17		Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed September 14, 2006).

10.18		Form of First Amendment to Change of Control Severance Agreement (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed September 14, 2006).

10.19		First Amendment to Energy Partners, Ltd. Change of Control Severance Plan (incorporated by reference to Exhibit 10.3 of the Company’s Form 8-K filed September 14, 2006).

31.1		Rule 13a-14(a)/15d-14(a) Certification of Chairman and Chief Executive Officer of Energy Partners, Ltd.

31.2		Rule 13a-14(a)/15d-14(a) Certification of Executive Vice President and Chief Financial Officer of Energy Partners, Ltd.

32.0		Section 1350 Certifications

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