Edgar Filing: ENERGY PARTNERS LTD

Form 10-Q for the Period Ended March 31, 2006.

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 March 31, 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 May 2, 2006, there were 38,335,013 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 March 31, 2006 and December 31, 2005		3

Consolidated Statements of Operations for the three months ended March 31, 2006 and 2005		4

Consolidated Statements of Cash Flows for the three months ended March 31, 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		25

Item 4. Controls and Procedures		26

PART II	OTHER INFORMATION

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		27

Item 6. Exhibits		27

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Item 1. FINANCIAL STATEMENTS

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	March 31, 2006			December 31, 2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,725		$	6,789
Trade accounts receivable		66,945			78,326
Other receivables		61,906			49,303
Deferred tax assets		3,213			5,582
Prepaid expenses		1,055			3,179

Total current assets		135,844			143,179
Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties		1,265,479			1,189,078
Less accumulated depreciation, depletion and amortization		(463,793	)		(418,347	)

Net property and equipment		801,686			770,731
Other assets		12,434			13,284
Deferred financing costs — net of accumulated amortization of $5,418 in 2006 and $5,169 in 2005		3,841			4,091

	$	953,805		$	931,285

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	22,685		$	28,810
Accrued expenses		118,810			108,087
Fair value of commodity derivative instruments		4,464			9,875
Current maturities of long-term debt		—			109

Total current liabilities		145,959			146,881
Long-term debt		225,000			235,000
Deferred tax liabilities		97,461			87,559
Asset retirement obligation		58,138			56,039
Other		6,750			11,213

		533,308			536,692
Stockholders’ equity:
Common stock, par value $0.01 per share. Authorized 50,000,000 shares; issued and outstanding: 2006 — 41,575,739 shares; 2005 — 41,468,093 shares		417			415
Additional paid-in capital		353,579			348,863
Accumulated other comprehensive loss — net of deferred taxes of $3,503 in 2006 and $7,098 in 2005		(6,228	)		(12,619	)
Retained earnings		130,169			115,366
Treasury stock, at cost. 2006 — 3,474,575 shares; 2005 — 3,474,208 shares		(57,440	)		(57,432	)

Total stockholders’ equity		420,497			394,593
Commitments and contingencies

	$	953,805		$	931,285

See accompanying notes to consolidated financial statements.

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ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(In thousands, except per share data)


	Three Months Ended March 31,
	2006			2005
Revenue:
Oil and natural gas	$	109,124		$	97,453
Other		994			25

		110,118			97,478

Costs and expenses:
Lease operating		12,365			12,443
Transportation expense		248			160
Taxes, other than on earnings		2,995			2,764
Exploration expenditures, dry hole costs and impairments		19,596			10,755
Depreciation, depletion and amortization		47,145			25,513
General and administrative		12,456			9,900

Total costs and expenses		94,805			61,535

Business interruption recovery		12,689			—
Income from operations		28,002			35,943

Other income (expense):
Interest income		279			185
Interest expense		(5,084	)		(4,048	)

		(4,805	)		(3,863	)

Income before income taxes		23,197			32,080
Income taxes		(8,394	)		(11,659	)

Net income		14,803			20,421
Less dividends earned on preferred stock and accretion of Discount		—			(944	)

Net income available to common stockholders	$	14,803		$	19,477

Basic earnings per share	$	0.39		$	0.56

Diluted earnings per share	$	0.37		$	0.51

Weighted average common shares used in computing income per share:
Basic		38,028			35,026
Incremental common shares
Preferred stock		—			2,205
Stock options		336			1,023
Warrants		1,899			1,889
Restricted share units		92			124
Performance shares		13			—

Diluted		40,368			40,267

See accompanying notes to consolidated financial statements.

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ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(In thousands)


	Three Months Ended March 31,
	2006			2005
Cash flows from operating activities:
Net income	$	14,803		$	20,421
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		47,145			25,513
Loss on disposition of assets		—			92
Non cash-based compensation		2,115			1,883
Deferred income taxes		8,677			11,309
Exploration expenditures		13,968			4,728
Amortization of deferred financing costs		249			247
Other		294			—
Changes in operating assets and liabilities:
Trade accounts receivable		11,381			(2,683	)
Other receivables		(12,603	)		(81	)
Prepaid expenses		2,124			1,282
Other assets		850			(1,292	)
Accounts payable and accrued expenses		(25,030	)		8,152
Other liabilities		(103	)		(128	)

Net cash provided by operating activities		63,870			69,443

Cash flows used in investing activities:
Acquisition of business, net of cash acquired		(420	)		(863	)
Property acquisitions		(7,872	)		(169,008	)
Exploration and development expenditures		(49,394	)		(51,176	)
Other property and equipment additions		(171	)		(406	)

Net cash used in investing activities		(57,857	)		(221,453	)

Cash flows provided by (used in) financing activities:
Equity offering costs		—			(87	)
Deferred financing costs		—			(354	)
Repayments of long-term debt		(30,109	)		(10,026	)
Proceeds from long-term debt		20,000			70,000
Exercise of stock options and warrants		32			2,129

Net cash provided by (used in) financing activities		(10,077	)		61,662

Net decrease in cash and cash equivalents		(4,064	)		(90,348	)
Cash and cash equivalents at beginning of period		6,789			93,537

Cash and cash equivalents at end of period	$	2,725		$	3,189

See accompanying notes to consolidated financial statements.

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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, current reports on Form 8-K and all related amendments. The Company’s website and the information contained in it and connected to it shall not be deemed incorporated by reference into this report on Form 10-Q.

The financial information as of March 31, 2006 and for the three month periods ended March 31, 2006 and 2005 have 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 three 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

As of April 30, 2006, the Company had two stock award plans, the Amended and Restated 2000 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 quarter ended March 31, 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 months ended March 31, 2006, no excess tax benefits were reported in the statement of cash flows as the Company is in a net operating loss carryforward position.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

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 Amended and Restated 2000 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 amended Employee Plan was approved by stockholders on May 9, 2002 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 is 4,800,000.

The Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors (the Director Plan) was approved by the Board of Directors and 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 advice 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, the director shall forfeit any unvested restricted share units.

During the three month period ended March 31, 2006, the Company recognized compensation expense of $0.9 million for option shares, $1.3 million for non-vested share awards and a benefit of $0.3 million for performance awards. The benefit resulted from the expiration of unvested performance shares granted in 2003 Of the $0.9 million option expense included in the Company’s statements of operations for the quarter ended March 31, 2006, $0.8 million relates to awards granted prior to January 1, 2006. The deferred income tax benefit recognized during that same period for the awards was $0.7 million. During the three month period ended March 31, 2005, the Company recognized $0.5 million of compensation expense for option shares due to the modification of an award under Opinion No. 25, and recognized $0.8 million for non-vested share awards and $0.6 million for performance share awards. Total deferred income tax benefit recognized during that same period for share awards was $0.7 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

The following table illustrates the effect on net income and earnings per common share for the three months ended March 31, 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 March 31, 2005
	(in thousands, except per share amounts)
Net income available to common stockholders:
As reported	$	19,477
Less: Pro forma net stock based employee compensation cost, after tax		80

Pro forma	$	19,557

Basic earnings per share:
As reported	$	0.56
Pro forma	$	0.56
Diluted earnings per share:
As reported	$	0.51
Pro forma	$	0.51
Stock-option based employee compensation cost, net of tax, included in net income as reported	$	348

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-month periods ended March 31, 2006 and 2005:


	Three Months Ended March 31,
	2006		2005
Black-Scholes option pricing model assumptions:
Risk free interest rate	4.4	%	4.5	%
Expected life (years)	4.7	9	5.0	0
Expected volatility	42.0	%	43.0	%
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 Reserves 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

A summary of option share activity for the three month period ended March 31, 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	294,463			22.70
Exercised	(4,000	)		7.98
Forfeited/Cancelled	—			—

Outstanding on March 31, 2006	2,118,572		$	17.06	6.9	$	36,144
Exercisable on March 31, 2006	1,076,766		$	11.99	6.3	$	12,915

The weighted-average grant-date fair value of option shares granted during the three month periods ended March 31, 2006 and 2005 was $9.60 and $11.08, 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 March 31, 2006 and March 31, 2005 was $0.1 million and $3.5 million, respectively. The following table summarizes information about option shares outstanding at March 31, 2006:


		Options Outstanding			Options Exercisable
Range of Exercise Prices	Shares	Remaining Contractual Life	Weighted Average Price		Shares	Weighted Average Price
$7.00 – $14.00	1,109,709	6.6 years	$	10.86	919,564	$	10.63
$14.01 – $21.00	126,100	6.3 years	$	16.56	92,767	$	15.70
$21.01 – $28.00	882,763	7.4 years	$	24.93	64,435	$	26.18

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 March 31, 2006 and 2005 was $22.37 per share and $26.60 per share, respectively. The total fair value of non-vested share awards that vested during each of the three month periods ended March 31, 2006 and 2005 was $0.9 million and $1.6 million, respectively. A summary of the status of the Company’s non-vested share awards as of March 31, 2006 and changes during the three month period ended March 31, 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	147,815			22.37
Vested	(39,159	)		26.74
Forfeited/Cancelled	(5,800	)		19.75

Non-vested share awards outstanding at March 31, 2006	759,485		$	22.78

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

In 2003 through 2005, performance shares were awarded to key officers and employees with the number of shares to be issued upon vesting, at the end of their respective three year cycles, 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 three month period ended March 31, 2006, 55,111 shares vested and were awarded and 27,556 shares expired unvested leaving 347,590 shares reserved based on the maximum award available, of which 139,296 shares are considered probable of vesting as of March 31, 2006.

As of March 31, 2006, there was $1.2 million of total unrecognized compensation expense related to option shares granted which is expected to be recognized over a weighted-average period of 2.1 years. As of March 31, 2006, there was $12.0 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 2.8 years and as of March 31, 2006, there was $1.4 million of total unrecognized compensation expense related to performance shares granted which is expected to be recognized over a weighted-average period of 1.5 years.

(3) ACQUISITIONS

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, and $38.4 million of 11% Senior Subordinated Notes (the Notes) due 2009 (immediately callable at par). On February 28, 2005, the Company gave notice of the redemption of all of the Series D Preferred Stock issued in connection with the acquisition that remained outstanding on the redemption date of March 21, 2005. The redemption price was $100 per share plus accrued and unpaid dividends to the redemption date. Holders of record had the right to convert their shares into shares of common stock through the close of business on March 18, 2005. All holders exercised their right to convert their shares and there were no preferred shares outstanding as of the close of business on March 18, 2005.

The Company also issued warrants to purchase four million shares of the Company’s common stock in the same 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 March 31, 2006 there were 741,026 warrants outstanding with a strike price of $9.00 per share and 2,615,518 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.

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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 preliminary closing adjustments. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. The acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells, with estimated acquisition date proved reserves of 51.2 billion cubic feet equivalent. Also included were interests in 22 exploratory prospects. The transaction expanded the Company’s exploration opportunities in its expanded focus area and further reduced the concentration of its reserves and production. Concurrent with the closing, the borrowing base under the Company’s bank credit facility was increased to $150 million, of which $60 million was drawn to fund the acquisition. In connection with the acquisition, the Company also entered into a two-year agreement with the seller of the properties that defines an area of mutual interest (AMI) encompassing over one million acres. The Company intends to continue to explore and develop oil and natural gas reserves in the AMI over that two year period jointly with the seller. The proved reserves, prospects and AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

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

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

(4) COMMON STOCK

In the first quarter of 2006, the Company acquired 367 shares of its common stock as a result of a tax withholding in connection with employee benefit transactions. All of these shares are reflected in treasury stock in the Consolidated Balance Sheet.

(5) 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.

(6) 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

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 March 31, 2006:


Natural Gas Positions
			Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Daily	Total
04/06 – 12/06	Collar	$5.00/$9.51	15,000	4,125,000
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 months ended March 31, 2006 and reduced natural gas revenues by $1.0 million in the three months ended March 31, 2006. The Company has not discontinued hedge accounting treatment in the periods presented, and therefore, has not reclassified any gains or losses into earnings as a result.

The following tables reconcile the change in accumulated other comprehensive income for the three month period ending March 31, 2006 and 2005.


	Three Months Ended March 31, 2006
	(in thousands)
Accumulated other comprehensive loss as of December 31, 2005 — net of taxes of $7,098			$	(12,619	)
Net income	$	14,803
Other comprehensive loss — net of tax
Hedging activities
Reclassification adjustments for settled contracts — net of taxes of $(347)		617
Changes in fair value of outstanding hedging positions — net of taxes of $(3,248)		5,774

Total other comprehensive loss		6,391		6,391

Comprehensive income	$	21,194

Accumulated other comprehensive loss as of March 31, 2006 — net of taxes of $3,503			$	(6,228	)

-12-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)


	Three Months Ended March 31, 2005
	(in thousands)
Accumulated other comprehensive loss as of December 31, 2004 — net of taxes of $630				$	(1,119	)
Net income	$	20,421
Other comprehensive loss — net of tax
Hedging activities
Reclassification adjustments for settled contracts — net of taxes of $(380)		676
Changes in fair value of outstanding hedging positions — net of taxes of $3,891		(6,918	)

Total other comprehensive loss		(6,242	)		(6,242	)

Comprehensive income	$	14,179

Accumulated other comprehensive loss as of March 31, 2005 — net of taxes of $4,140				$	(7,361	)

Based upon current prices, the Company expects to transfer approximately $4.5 million of pretax net deferred losses in accumulated other comprehensive loss as of March 31, 2006 to earnings during the next twelve months when the forecasted transactions actually occur.

(7) 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.

(8) 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 three months ended March 31, 2006.


	Three Months Ended March 31, 2006
	(in thousands)
December 31, 2005	$	56,039
Accretion expense		1,093
Liabilities incurred		1,046
Liabilities settled		(40	)

March 31, 2006	$	58,138

-13-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

(9) INDEBTEDNESS

On August 5, 2003, the Company issued $150 million of 8.75% Senior Notes Due 2010 (the Senior Notes) in a Rule 144A private offering (the Debt Offering) which allows unregistered transactions with qualified institutional buyers. In October 2003, the Company consummated an exchange offer pursuant to which it exchanged registered Senior Notes (the Registered Senior Notes) having substantially identical terms as the Senior Notes for the privately placed Senior Notes. After discounts and commissions and estimated offering expenses, the Company received $145.3 million, which was used to redeem all of the outstanding 11% Senior Subordinated Notes Due 2009, that had been issued in connection with a business combination in 2002, and to repay substantially all of the borrowings outstanding under the Company’s bank credit facility. In January 2005 the remainder of the net proceeds were used to purchase properties in south Louisiana as discussed in note (3).

The Registered Senior Notes mature on August 1, 2010 with interest payable each February 1 and August 1, commencing February 1, 2004. The indenture relating to the Registered Senior Notes contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on its common stock, make investments, create liens on its assets, engage in transactions with its affiliates, transfer or sell assets and consolidate or merge substantially all of its assets. The Registered Senior Notes are not subject to any sinking fund requirements.

On August 3, 2004, the Company amended and extended to August 3, 2008 its bank credit facility. The borrowing base was increased to $150 million at the time of the Company’s purchase of south Louisiana properties and reserves in January 2005. At March 31, 2006 the Company had $75.0 million outstanding under the bank credit facility. The borrowing base remains subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility as set out in the reserve report delivered to the banks each April 1 and October 1.

(10) TROPICAL WEATHER

On August 29, 2005 Hurricane Katrina made landfall in the United States south of New Orleans causing catastrophic damage throughout portions of the Gulf of Mexico and to portions of Alabama, Louisiana and Mississippi, including New Orleans. As a result of the devastating effects of the storm on New Orleans and surrounding areas, the Company announced on August 30 that it had elected to establish temporary headquarters at its Houston, Texas office. A satellite office was also established in Baton Rouge, Louisiana. General and administrative costs associated with moving offices as well as relocation allowances paid to employees approximated $1.6 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 a portion of that production had not yet been restored at the end of the first quarter of 2006. The Company is continuing to work to bring production back to pre-storm levels, but is subject to constraints due to damage to third party infrastructure. In 2005 the Company maintained business interruption insurance 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 and recovery on a fourth field began accruing in November. Recovery ceased for three of the fields in 2005, but will continue until production is restored to pre-storm levels at the East Bay field, subject to policy limits that the Company does not expect at this time to be reached. Through March 31, 2006, the total business interruption claim on these fields was $33.3 million, of which $15.8 million had not been collected as of March 31, 2006 and is recorded in other receivables on the Company’s consolidated balance sheet. As of April 30, 2006, an additional $1.4 million of this amount had been collected. Total offshore repair costs expended as of March 31, 2006 subject to insurance recoveries, in excess of applicable deductibles, for Hurricanes Katrina, Rita and Cindy were $43.1 million which is recorded in other receivables on the Company’s consolidated balance sheet.

-14-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

(11) 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 nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement 153 does not apply to a pooling of assets in a joint undertaking intended to fund, develop, or produce oil or natural gas from a particular property or group of properties. The provisions of Statement 153 effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early adoption is permitted and the provisions of Statement 153 should be applied prospectively. The Company 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.

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 153 which will not have an impact on the Company’s 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. The Company has assessed the impact of Statement 153 which will not have an impact on the Company’s financial position, results of operations or cash flows.

(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.

-15-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(UNAUDITED)

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

Supplemental Condensed Consolidating Balance Sheet

As of March 31, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,725		$	—		$	—		$	2,725
Accounts receivable		137,789			(8,938	)		—			128,851
Other current assets		4,206			62			—			4,268

Total current assets		144,720			(8,876	)		—			135,844
Property and equipment		845,037			420,442			—			1,265,479
Less accumulated depreciation, depletion and amortization		(323,484	)		(140,309	)		—			(463,793	)

Net property and equipment		521,553			280,133			—			801,686
Investment in affiliates		230,893			254			(231,147	)		—
Notes receivable, long-term		—			216,370			(216,370	)		—
Other assets		16,296			(21	)		—			16,275

	$	913,462		$	487,860		$	(447,517	)	$	953,805


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	140,346		$	1,149		$	—		$	141,495
Fair value of commodity derivative instruments		4,464			—			—			4,464

Total current liabilities		144,810			1,149			—			145,959
Long-term debt		225,000			216,370			(216,370	)		225,000
Other liabilities		123,155			39,194			—			162,349

		492,965			256,713			(216,370	)		533,308
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		417			97			(97	)		417
Additional paid-in capital		353,579			411			(411	)		353,579
Accumulated other comprehensive loss		(6,228	)		—			—			(6,228	)
Retained earnings		130,169			230,636			(230,636	)		130,169
Treasury stock		(57,440	)		—			—			(57,440	)

Total stockholders’ equity		420,497			231,147			(231,147	)		420,497

	$	913,462		$	487,860		$	(447,517	)	$	953,805

-16-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

Supplemental Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenue:
Oil and natural gas	$	61,429		$	47,695		$	—		$	109,124
Other		(3,670	)		61			4,603			994

		57,759			47,756			4,603			110,118
Costs and expenses:
Lease operating		103			12,510			—			12,613
Taxes, other than on earnings		236			2,759			—			2,995
Exploration expenditures		8,745			10,851			—			19,596
Depreciation, depletion and amortization		21,152			25,993			—			47,145
General and administrative		12,211			3,995			(3,750	)		12,456

Total costs and expenses		42,447			56,108			(3,750	)		94,805
Business interruption recovery		12,689			—			—			12,689
Income from operations		28,001			(8,352	)		8,353			28,002

Interest expense, net		(4,804	)		(1	)		—			(4,805	)

Income before income taxes		23,197			(8,353	)		8,353			23,197
Income taxes		(8,394	)		—			—			(8,394	)

Net income	$	14,803		$	(8,353	)	$	8,353		$	14,803

-17-

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(UNAUDITED)

Supplemental Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)
Net cash provided by operating activities	$	49,500		$	14,370		$	—	$	63,870
Cash flows used in investing activities:
Acquisition of business, net of cash acquired		(420	)		—			—		(420	)
Property acquisitions		(7,872	)		—			—		(7,872	)
Exploration and development expenditures		(35,133	)		(14,261	)		—		(49,394	)
Other property and equipment additions		(171	)		—			—		(171	)

Net cash used in investing activities		(43,596	)		(14,261	)		—		(57,857	)

Cash flows used in financing activities:
Repayments of long-term debt		(30,000	)		(109	)		—		(30,109	)
Proceeds from long-term debt		20,000			—			—		20,000
Exercise of stock options and warrants		32			—			—		32

Net cash used in financing activities		(9,968	)		(109	)		—		(10,077	)

Net decrease in cash and cash equivalents		(4,064	)		—			—		(4,064	)
Cash and cash equivalents at beginning of period		6,789			—			—		6,789

Cash and cash equivalents at end of period	$	2,725		$	—		$	—	$	2,725

(13) CONTINGENCIES

In the ordinary course of business, the Company is a defendant in various legal proceedings. The Company does not expect its exposure in these proceedings, individually or in the aggregate, to have a material adverse effect on the financial position, results of operations or liquidity of the Company.

(14) RECLASSIFICATIONS

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

-18-

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 to 2005 and continued to affect us in the first quarter of 2006, we have still made 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 undeveloped acreage in the first quarter of 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 August 3, 2004, we amended and extended to August 3, 2008 our bank credit facility. The borrowing base was increased to $150 million at the time of our purchase of south Louisiana properties and reserves in January 2005. At March 31, 2006 the Company had $75 million outstanding under the bank credit facility. The borrowing base remains subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility. The Company’s borrowing base was reaffirmed effective November 1, 2005.

On January 20, 2005, we closed an acquisition of properties and reserves in south Louisiana for $149.6 million in cash, after adjustments for the exercise of preferential rights by third parties and preliminary closing adjustments. The acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells, with estimated acquisition date proved reserves of 51.2 billion cubic feet equivalent. Also included were interests in 22 exploratory prospects. The transaction expanded the exploration opportunities in our expanded focus area and further reduced the concentration of our reserves and production. Upon the signing of the purchase agreement, we paid a $5.0 million deposit in 2004 toward the purchase price which was recorded as other assets in the consolidated balance sheet as of December 31, 2004, and concurrent with the closing, the borrowing base under our bank credit facility was increased to $150 million, of which $60 million was drawn to fund the acquisition. In connection with the acquisition, we also entered into a two-year agreement with the seller of the properties that defined an area of mutual interest (“AMI”) encompassing over one million acres. We intend to continue to explore and develop oil and natural gas reserves in the AMI over the two year term jointly with the seller. The proved reserves, prospects and the AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

-19-

On March 8, 2005, we closed the acquisition of the remaining 50% gross working interest in South Timbalier 26 above approximately 13,000 feet subsea that we did not already own for approximately $19.6 million after preliminary closing adjustments from the effective date of December 1, 2004. As a result of the acquisition, we now own a 100% gross working interest in the producing horizons in this field. The acquisition expands our interest in our core Greater Bay Marchand area and gives us additional flexibility in undertaking the future development of the South Timbalier 26 field.

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

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 and a portion of that production had not yet been restored by the end of the first quarter of 2006. We are continuing to work to bring back shut-in production, but are subject to constraints due to damage to third party infrastructure. 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 two other fields began accruing in October 2005 while recovery on a fourth field began accruing in December 2005. Through March 31, 2006, we had recorded $33.3 million for business interruption recoveries of which $12.7 million and $20.6 million was recorded in the statement of operations in the first quarter of 2006 and fourth quarter of 2005, respectively. Production was fully restored in three of these fields in 2005, at which time coverage ceased, and recoveries will continue to accrue at East Bay Field until production is fully restored, subject to policy limits that we do not expect at this time to be reached.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, tropical weather and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil and natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We currently have an extensive inventory of drillable prospects in-house, we are generating more prospects internally and we are exploring new opportunities through relationships with industry partners. Despite our expanded budget in 2006, strong commodity prices applied to our produced volumes, even after taking into account the effect of the Tropical Weather in 2005 on those volumes, should enable us to adhere to our policy of funding our exploration and development expenditures with internally generated cash flow. This strategy allows us to preserve our balance sheet to finance acquisitions and other capital intensive projects that might result from exploration and development activities. We believe the near term may provide us with opportunities to acquire targeted properties, including those within our focus area.

-20-

RESULTS OF OPERATIONS

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

REVENUES AND NET INCOME


	Three Months Ended March 31,
	2006			2005
Net production (per day):
Oil (Bbls)		7,185			9,978
Natural gas (Mcf)		94,833			96,172
Total barrels of oil equivalent (Boe)		22,991			26,007
Oil and natural gas revenues (in thousands):
Oil	$	38,253		$	41,019
Natural gas		70,871			56,434
Total		109,124			97,453
Average sales prices, net of hedging:
Oil (per Bbl)	$	59.16		$	45.68
Natural gas (per Mcf)		8.30			6.52
Total (per Boe)		52.74			41.64
Impact of hedging:
Oil (per Bbl)	$	—		$	(1.17	)
Natural gas (per Mcf)		(0.11	)		—
Average costs (per Boe):
Lease operating expense	$	5.98		$	5.32
Taxes, other than on earnings		1.45			1.18
Depreciation, depletion and amortization		22.78			10.90
Increase in oil and natural gas revenues between periods presented (in thousands, net of hedging) due to:
Changes in prices of oil	$	12,106
Changes in production volumes of oil		(14,872	)
Total decrease in oil sales		(2,766	)
Changes in prices of natural gas	$	15,439
Changes in production volumes of natural gas		(1,002	)
Total increase in natural gas sales		14,437

Our oil and natural gas revenues increased to $109.1 million in the first quarter of 2006 from $97.5 million in the first quarter of 2005. The increase for this period is the result of an increase in oil and natural gas prices although production decreased during the comparative periods due to the Tropical Weather related damage to third party infrastructure still awaiting repairs.

We recognized net income of $14.8 million in the first quarter of 2006 compared to net income of $20.4 million in the first quarter of 2005. The decrease was due to the impact of the Tropical Weather on production discussed above as well as increased operating costs including dry hole costs discussed below partially offset by increased oil and natural gas prices and business interruption recoveries.

OPERATING EXPENSES

Operating expenses during the three months ended March 31, 2006 and 2005 were affected by the following:

•

Lease operating expense remained constant at $12.4 million in the first quarter of 2006 compared the first quarter of 2005. However, lease operating expense per Boe increased in the first quarter of 2006 compared to the first quarter of 2005. This increase per Boe is primarily the result of costs returning to levels that existed before the Tropical Weather while production was lower due to damage to third party infrastructure.

-21-

•

Taxes, other than on earnings, increased slightly to $3.0 million in the first quarter of 2006 from $2.8 million in the first quarter of 2005. The increase was due to the increase in commodity prices and production from non-federal leases as a result of the south Louisiana property acquisition in mid-January 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, increased to $19.6 million in the first quarter of 2006 from $10.8 million in the first quarter of 2005. The largest contributor of the change was a dry hole at our Denali prospect of approximately $7.5 million. The expense in the first quarter of 2006 is comprised of $13.9 million of costs for exploratory wells or portions thereof which were found to be not commercially productive and $5.6 million of seismic expenditures and delay rentals. Seismic expenditures in 2006 includes seismic on deepwater prospects. The expense in the first quarter of 2005 is comprised of $4.8 million of costs for exploratory wells or portions thereof which were found to be not commercially productive and $6.0 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 and the level of success we achieve in exploratory drilling activities.

•

Depreciation, depletion and amortization increased to $47.1 million in the first quarter of 2006 from $25.5 million in the first quarter of 2005. The increase was a result of an increase in the depreciable asset base and a shift in the production contribution from our various fields as well as reserve revisions taken on our onshore properties in 2005. Some fields carry a higher depreciation burden than others; therefore, changes in the sources of our production will directly impact this expense.

•

General and administrative expenses increased to $12.5 million in the first quarter of 2006 from $9.9 million in the first quarter of 2005. Included in this expense is stock based compensation of $1.9 million in both 2006 and 2005. The overall increase was primarily increased personnel and insurance costs in 2006.

OTHER INCOME AND EXPENSE

Interest expense increased to $5.1 million in the first quarter of 2006 from $4.0 million in the first quarter of 2005. The increase was a result of an increase in the interest rate as well as the average borrowings in the first quarter of 2006 compared to the first quarter of 2005 on borrowings under our bank credit facility to finance acquisitions.

LIQUIDITY AND CAPITAL RESOURCES

The trend of increased revenues we have experienced from 2005 into the first three months of 2006 has continued to provide strong cash flows from operations which totaled $63.9 million in the first three 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 March 31, 2006 was $2.7 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. We may, from time to time, use our bank credit facility to fund working capital needs.

Our bank credit facility, as amended on August 3, 2004, consists of a revolving line of credit with a group of banks available through August 3, 2008 (the “bank credit facility”). The bank credit facility currently has a borrowing base of $150 million that is subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility as set out in the reserve report delivered to the banks each April 1 and October 1. The bank credit facility permits both prime rate borrowings and London interbank offered rate (“LIBOR”) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank credit facility. The spread can range from 1.25% to 2.00% above LIBOR and 0% to 0.75% above prime. The borrowing base under the bank credit facility is secured by substantially all of our assets. We used our bank credit facility to fund a portion of the purchase of the south Louisiana properties in January 2005 and the acquisition of the

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additional interest in South Timbalier 26 in March 2005. At May 2, 2006 we had $115 million outstanding and $35 million of credit capacity available under the bank credit facility. In addition, we pay an annual fee on the unused portion of the bank credit facility ranging between 0.375% to 0.5% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require us to: (i) maintain a minimum current ratio, as defined in our bank credit facility agreement, of 1.0 and (ii) maintain a minimum EBITDAX to interest ratio, as defined in our bank credit facility agreement, of 3.5. We were in compliance with the bank credit facility covenants as of March 31, 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, beginning February 1, 2004. We may redeem the Senior Notes at our option, in whole or in part, at any time on or after August 1, 2007 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 4.375% in 2007 to 0% in 2009 and thereafter. In addition, at any time prior to August 1, 2006, we may redeem up to a maximum of 35% of the aggregate principal amount with the net proceeds of certain equity offerings at a price equal to 108.75% of the principal amount, plus accrued and unpaid interest. The notes are unsecured obligations and rank equal in right of payment to all existing and future senior debt, including the bank credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness. The indenture relating to the Senior Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets and consolidate or merge substantially all of our assets. The Senior Notes are not subject to any sinking fund requirements.

Net cash of $57.9 million used in investing activities in the first three 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 three months of 2006, we completed six drilling projects, five of which were successful, and 10 recompletion/workover projects, all of which were successful. During the first three months of 2005, we completed 15 drilling projects, 12 of which were successful, and seven recompletion/workover projects, all of which were successful.

Our 2006 capital exploration and development budget is focused on exploitation and development activities on our proved properties combined with moderate risk and higher risk exploratory activities on undeveloped leases and our proved properties, and does not include acquisitions. We continue to manage our portfolio in order to maintain an appropriate risk balance between low risk development and exploitation activities, moderate risk exploration opportunities and higher risk, higher potential exploration opportunities. Currently, our exploration and development budget for 2006 is approximately $360 million. We do not budget for acquisitions. During the first three months of 2006, capital and exploration expenditures were approximately $92.5 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 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.

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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 three months ended March 31, 2006. 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 nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement 153 does not apply to a pooling of assets in a joint undertaking intended to fund, develop, or produce oil or natural gas from a particular property or group of properties. The provisions of Statement 153 shall be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early adoption is permitted and the provisions of Statement 153 should be applied prospectively. 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 153 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 153 which will not have an impact on our financial position, results of operations or cash flows.

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FORWARD LOOKING INFORMATION

All statements other than statements of historical fact contained in this Report on Form 10-Q (“Report”) and other periodic reports filed by us under the Securities Exchange Act of 1934 and other written or oral statements made by us or on our behalf, are forward-looking statements. When used herein, the words “anticipates”, “expects”, “believes”, “goals”, “intends”, “plans”, or “projects” and similar expressions are intended to identify forward-looking statements. It is important to note that forward-looking statements are based on a number of assumptions about future events and are subject to various risks, uncertainties and other factors that may cause our actual results to differ materially from the views, beliefs and estimates expressed or implied in such forward-looking statements. We refer you specifically to the section “Risk Factors” in Item 1A 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 March 31, 2006, $75.0 million of our long-term debt had variable interest rates while the remaining long-term debt had fixed interest expense. If the market interest rates had averaged 1% higher in the first 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 $0.2 million based on total variable debt outstanding during the period. If market interest rates had averaged 1% lower in the first 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 $0.2 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 March 31, 2006, we had the following contracts in place:


Natural Gas Positions
			Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Daily	Total
04/06 – 12/06	Collar	$5.00/$9.51	15,000	4,125,000
01/07 – 12/07	Collar	$5.00/$8.00	10,000	3,650,000

Inclusive of the storm implications on our near term forecasted production, our hedged volume as of March 31, 2006 approximated 7% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at March 31, 2006, we estimate the pre-tax loss would have been $9.7 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 March 31, 2006, the potential change in the fair value of commodity derivative instruments assuming a 10% increase in the underlying commodity price was a $3.6 million increase in the combined estimated pre tax loss.

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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 March 31, 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.

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Part II. OTHER INFORMATION

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

Issuer Purchases of Equity Securities


Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share (1)	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (1)
1/1/06 – 1/31/06	—	n/a	n/a	n/a
2/1/06 – 2/28/06	—	n/a	n/a	n/a
3/1/06 – 3/31/06	367	22.14	n/a	n/a

Total	367	22.14	n/a	n/a

(1)	Shares were acquired from employees as part of a benefit plan agreement and were not purchased as part of a publicly announced plan or program.

Item 6. EXHIBITS


Exhibits:

3.6		Amendment to Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of May 5, 2006.

31.0		Rule 13a-14(a)/15d-14(a) Certification of Chairman and Chief Executive Officer (principal executive officer and principal financial officer) of Energy Partners, Ltd.

32.0		Section 1350 Certification

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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: May 9, 2006	By:	/s/ Richard A. Bachmann
		Richard A. Bachmann
		Chairman and Chief Executive Officer
		(authorized officer and principal financial officer)

Date: May 9, 2006	By:	/s/ Dina Bracci Riviere
		Dina Bracci Riviere
		Controller
		(principal accounting officer)

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EXHIBIT INDEX


Exhibit Number		Description of Exhibit

3.6		Amendment to Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of May 5, 2006.

31.0		Rule 13a-14(a)/15d-14(a) Certification of Chairman and Chief Executive Officer (principal executive officer and principal financial officer) of Energy Partners, Ltd.

32.0		Section 1350 Certification

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