Epl Oil & Gas 10-Q 2008 Q3 Quarterly report

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, 2008

OR

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

Commission file number 001-16179

ENERGY PARTNERS, LTD.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	72-1409562
(State or Other Jurisdiction 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, a non-accelerated filer, or smaller reporting company. See definitions of “large accelerated filers”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer  x
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company  ¨

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 5, 2008, there were31,912,310 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, 2008 and December 31, 2007	3
	Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and 2007	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	22
Item 4.	Controls and Procedures	23
PART II OTHER INFORMATION
Item 6.	Exhibits	25

2

Item 1. FINANCIAL STATEMENTS

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	March 31, 2008			December 31, 2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	13,845		$	8,864
Trade accounts receivable		42,564			52,139
Deferred tax assets		1,852			3,865
Prepaid expenses		1,961			1,640
Total current assets		60,222			66,508
Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties		1,582,737			1,547,003
Less accumulated depreciation, depletion and amortization		(852,950	)		(824,397	)
Net property and equipment		729,787			722,606
Other assets		15,885			15,556
Deferred financing costs — net of accumulated amortization of $2,507 in 2008 and $2,100 in 2007		9,779			10,186
	$	815,673		$	814,856
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	16,609		$	14,369
Accrued expenses		108,596			104,555
Fair value of commodity derivative instruments		12,806			9,124
Total current liabilities		138,011			128,048
Long-term debt		474,501			484,501
Deferred tax liabilities		19,931			20,880
Asset retirement obligation		71,566			73,350
Fair value of commodity derivative instruments		4,017			4,602
Other		1,475			1,505
		709,501			712,886
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: 2008—44,113,392 shares; 2007—43,980,644 shares; outstanding, net of treasury shares: 2008—31,873,406 shares; 2007—31,740,658 shares		442			441
Additional paid-in capital		376,760			374,874
Accumulated deficit		(12,674	)		(14,989	)
Treasury stock, at cost. 2008 — 12,239,986 shares; 2007 — 12,239,986 shares		(258,356	)		(258,356	)
Total stockholders’ equity		106,172			101,970
Commitments and contingencies
	$	815,673		$	814,856

See accompanying notes to consolidated financial statements.

3

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(In thousands, except per share data)

	Three Months Ended March 31,
	2008			2007
Revenue:
Oil and natural gas	$	97,455		$	108,402
Other		41			61
		97,496			108,463
Costs and expenses:
Lease operating		14,214			16,749
Transportation		406			459
Exploration expenditures, dry hole costs and impairments		23,209			21,801
Depreciation, depletion and amortization		28,810			47,920
Accretion		1,056			1,100
General and administrative		9,367			22,395
Taxes, other than on earnings		2,379			2,870
Gain on insurance recoveries		—			(8,084	)
Gain on sale of assets		(6,674	)		—
Other		1,096			—
Total costs and expenses		73,863			105,210
Business interuption recovery		—			9,084
Income from operations		23,633			12,337
Other income (expense):
Interest income		301			180
Interest expense		(11,912	)		(6,757	)
Gain (loss) on derivative instruments		(8,326	)		—
		(19,937	)		(6,577	)
Income before income taxes		3,696			5,760
Income taxes		(1,381	)		(2,064	)
Net income		2,315			3,696
Basic earnings per share	$	0.07		$	0.09
Diluted earnings per share	$	0.07		$	0.09
Weighted average common shares used in Computing earnings per share:
Basic		31,772			40,157
Incremental common shares
Stock options		—			91
Warrants		—			58
Restricted share units		—			177
Performance shares		7			—
Diluted		31,779			40,483

See accompanying notes to consolidated financial statements.

4

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(In thousands)

	Three Months Ended March 31,
	2008			2007
Cash flows from operating activities:
Net income	$	2,315		$	3,696
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		28,810			47,921
Accretion		1,056			1,100
Unrealized loss on derivative contracts		3,096			—
Non cash-based compensation		1,466			2,139
Deferred income taxes		1,064			2,063
Gain on sale of oil and gas assets		(6,674	)		—
Exploration expenditures		21,632			16,663
Amortization of deferred financing costs		407			234
Gain on insurance recoveries		—			(8,084	)
Other		674			379
Changes in operating assets and liabilities:
Trade accounts receivable		8,728			3,818
Other receivables		—			56,006
Prepaid expenses		(321	)		(112	)
Other assets		(329	)		(152	)
Accounts payable and accrued expenses		3,080			(11,843	)
Other liabilities		(2,583	)		(38	)
Net cash provided by operating activities		62,421			113,790
Cash flows used in investing activities:
Insurance recoveries for property, plant and equipment		—			19,574
Property acquisitions		(15,341	)		(1,131	)
Exploration and development expenditures		(47,010	)		(100,070	)
Proceeds from sale of oil and gas assets		15,026			—
Other property and equipment additions		(216	)		(159	)
Net cash used in investing activities		(47,541	)		(81,786	)
Cash flows used in financing activities:
Repayments of long-term debt		(35,000	)		(60,000	)
Proceeds from long-term debt		25,000			58,000
Exercise of stock options and warrants		101			694
Net cash used in financing activities		(9,899	)		(1,306	)
Net increase in cash and cash equivalents		4,981			30,698
Cash and cash equivalents at beginning of period		8,864			3,214
Cash and cash equivalents at end of period	$	13,845		$	33,912

See accompanying notes to consolidated financial statements.

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) BASIS OF PRESENTATION

Certain information and footnote disclosures normally in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to rules and regulations of the Securities and Exchange Commission; however, management believes the disclosures which are made are adequate to make the information presented not misleading. These financial statements and footnotes should be read in conjunction with the financial statements and notes thereto included in Energy Partners, Ltd.’s (the Company) Annual Report on Form 10-K for the year ended December 31, 2007 and Management’s Discussion and Analysis of Financial Condition and Results of Operations. The Company maintains a website atwww.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 March 31, 2008 and for the three month periods ended March 31, 2008 and 2007 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 three months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

(2) MERGERS, ACQUISITIONS AND DIVESTITURES

On March 26 and 27, 2008, the Company completed the sale of two Gulf of Mexico Shelf properties located in its Western offshore area for $15.0 million after giving effect to preliminary closing adjustments. The Company recorded a gain on the sale of $7.1 million in the first quarter of 2008.

On June 12, 2007, the Company completed the sale of substantially all of the Company’s onshore South Louisiana assets to Castex Energy 2007, L.P. for $68.6 million after giving effect to closing adjustments. The Company used the proceeds to pay down a portion of its revolving credit facility. As of the closing date, the estimated proved reserves of the disposed properties totaled approximately 2.1 Mmboe. The Company recorded a gain of $6.5 million on this sale in the second quarter of 2007.

On October 12, 2006 the Company announced that its Board of Directors (the Board) had directed the Company, assisted by its financial and legal advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of the Company. On March 12, 2007 the Company announced that the Board had concluded its strategic alternatives process. As a result of this process, the Board, with advice from its financial and legal advisors and management, determined to continue with the execution of the Company’s strategic plan, augmented by a self-tender offer for up to 8,700,000 shares of its common stock at $23.00 per share, the refinancing of its bank credit facility and a tender offer for all of its existing $150 million aggregate principal amount of senior notes due 2010 (the Transactions), and the divestment of selected properties following the completion of the Transactions to reduce debt under the Company’s new bank credit facility. In order to fund the Transactions, the Company undertook a private offering of $450 million of senior unsecured notes and entered into a new bank credit facility. The Company incurred $8.8 million of financial and legal advisory fees during the first quarter of 2007 related to the exploration of strategic alternatives and the tender offers.

(3) COMMON STOCK

On March 12, 2007, the Company’s Board concluded its strategic alternatives process as discussed in note 2 above, which resulted in, among other things, an equity self-tender offer for up to 8,700,000 shares of its common stock at $23.00 per share and the authorization for the repurchase of up to $50 million of its common stock during the one year period following the completion of the equity self tender offer, subject to business and market conditions and any debt covenants restricting such repurchases. On April 23, 2007 the Company completed the equity self-tender offer and purchased 8,700,000 million shares of its common stock. In addition, during the year ended December 31, 2007 the Company acquired 59,500 shares of its common stock for $0.8 million, at an average price of $13.71 per share, in its stock repurchase program. All of these shares are reflected in treasury stock in the Consolidated Balance Sheets.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(4) EARNINGS PER SHARE

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

(5) DERIVATIVE TRANSACTIONS

The Company enters into derivative transactions with major financial institutions and others to reduce exposure to fluctuations in the price of oil and natural gas. While the use of these transactions limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. The Company’s Board has set limitations on the percentage of proved production that the Company can hedge. Crude oil hedges are primarily settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. Natural gas hedges are primarily settled based on the average of the last three days of trading of the NYMEX Henry Hub natural gas contract for each month.

The Company has primarily used financially-settled crude oil and natural gas zero-cost collars and put options to provide floor prices with varying upside price participation. With a zero-cost collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price is above the cap price for the collar. With a put option, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the strike price of the put and the Company has no obligations to the counterparty except for the payment of any option premium. On occasion, the Company may incorporate floors and/or collars into its production sales contracts which are settled under conventional marketing terms.

Prior to the second quarter of 2007, all derivative transactions that qualified for hedge accounting under Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” (Statement 133) as amended by Statement Nos. 137, 138 and 149 were designated on the date the Company entered into each transaction as a hedge of the variability in cash flows associated with the forecasted sale of future oil and natural gas production. After-tax changes in the fair value of a hedge that was highly effective and designated and qualified as a cash flow hedge, to the extent that the hedge was effective, was recorded as Accumulated Other Comprehensive Income (OCI) on the consolidated balance sheet until the sale of the hedged oil and natural gas production occurred. Upon the sale of the underlying hedged production, the net after-tax change in the fair value of the associated hedging transaction recorded in OCI was reversed and the resulting gain or loss on the settlement of the hedge, to the extent that it was effective, was reported in oil and natural gas revenues in the consolidated statement of operations. Once hedge accounting was discontinued prospectively effective April 2, 2007 for existing contracts and while the hedging contracts remained in effect they were carried at their fair value on the Consolidated Balance Sheets until settlement and all subsequent changes in fair value were recognized in the Consolidated Statements of Operations for the period in which the change occurred. All of these contracts were settled in 2007.

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

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company had the following derivative contracts as of March 31, 2008:

Natural Gas Positions
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Volume (Mmbtu)
			Daily	Total
04/08 – 06/08	Collar	$6.50/$11.15	20,000	1,820,000
11/08 – 12/08	Collar	$6.82/$15.38	20,000	1,220,000
01/09 – 03/09	Collar	$6.75/$17.15	10,000	900,000
Crude Oil Positions
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)	Volume (Bbls)
			Daily	Total
04/08 – 06/08	Collar	$55.00/$85.79	3,000	273,000
07/08 – 9/08	Put	$55.00	2,000	184,000
07/08 – 10/08	Collar	$55.00/$85.65	500	61,500
11/08 – 12/08	Collar	$55.00/$86.80	2,500	152,500
1/09 – 06/09	Collar	$55.00/$87.17	3,000	543,000

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

	Three Months Ended March 31,
	2008
Derivative contracts:
Unrealized loss due to change in fair market value	$	(3,096	)
Realized loss on settlement		(5,230	)
Total loss on derivative instruments	$	(8,326	)

Settlements of cash flow hedging contracts did not impact crude oil or natural gas revenues in the three month period ended March 31, 2007.

(6) OIL AND GAS PROPERTIES

At March 31, 2008, the Company had two projects whose exploratory well costs in the amount of $32.6 million were suspended and were capitalized for a period greater than one year. At March 31, 2007 the Company did not have any projects that were suspended for a period greater than one year.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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 three months ended March 31, 2008.

	Three Months Ended March 31, 2008
	(in thousands)
December 31, 2007	$	77,898
Accretion expense		1,056
Sale of properties		(321	)
Revisions		1,099
Liabilities incurred		722
Liabilities settled		(2,553	)
March 31, 2008	$	77,901

At March 31, 2008, and included above, asset retirement obligations required to be settled within the next twelve months of $6.3 million were included in accrued expenses on the Consolidated Balance Sheets.

(8) INDEBTEDNESS

On April 23, 2007 the Company refinanced its bank credit facility with a new $300 million revolving credit facility (the bank credit facility) with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the 2007 sale of assets described in Note 2, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. The bank credit facility is secured by substantially all of the Company’s assets. The bank credit facility permits both prime rate borrowings and London InterBank Offered Rate (LIBOR) borrowings plus a floating spread. The spread will float up or down based on utilization of the bank credit facility. The spread can range from 1.00% to 2.50% above LIBOR and 0% to 0.50% above prime. At March 31, 2008, the Company had $20 million outstanding under the bank credit facility and $180 million available under its borrowing base of $200 million in effect at that date. In addition, the Company pays an annual fee on the unused portion of the bank credit facility ranging between 0.25% to 0.50% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require the Company to: (i) maintain a minimum current ratio, as defined by the bank credit facility, of 1.0x, (ii) maintain a minimum Consolidated EBITDAX to interest ratio, as defined by the bank credit facility, of 2.5x, and (iii) maintain a ratio of long-term debt to Consolidated EBITDAX below 3.5x, which decreased to 3.0x on April 1, 2008. The Company was in compliance with the bank credit facility covenants as of March 31, 2008. 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 on or about each April 1 and October 1. On May 6, 2008, the Company’s bank credit facility was redetermined with a borrowing base of $150 million.

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

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

On May 4, 2007, the Company completed a cash tender offer for its $150 million 8.75% Senior Notes due 2010 (the Senior Notes). Approximately $145.5 million of these Senior Notes were repurchased and substantially all of their covenants have been removed.

A loss on early extinguishment of debt for the refinancing of the bank credit facility and the repurchase of the Senior Notes of approximately $10.8 million was recorded during the second quarter 2007. It included the write-off of unamortized deferred financing costs related to the bank credit facility and the Senior Notes as well as the consent fees relating to the tender for the Senior Notes.

(9) FAIR VALUE MEASUREMENTS

In September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurements” (Statement 157). Statement 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. The Company adopted Statement 157 effective January 1, 2008. Certain of the Company’s assets and liabilities are reported at fair value in the accompanying Consolidated Balance Sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The FASB agreed to a one year deferral of Statement 157’s fair value measurement requirements for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis such as asset retirement obligations and oil and natural gas property and equipment. The following tables provide fair value measurement information for such assets and liabilities as of March 31, 2008.

The carrying values of cash and cash equivalents, trade accounts receivable and accounts payable (including income taxes payable and accrued expenses) included in the accompanying Consolidated Balance Sheets approximated fair value at March 31, 2008. These assets and liabilities are not presented in the following tables.

	As of March 31, 2008
					Fair Value Measurements Using:
	Carrying Amount (In thousands)		Total Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Financial Assets (Liabilities):
Oil and natural gas puts and collars	$	16,823	$	16,823	$	—	$	16,823	$	—
Debt	$	474,501	$	401,961	$	381,961	$	20,000	$	—

Statement 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the table above, this hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are other than quoted prices in active markets included in Level 1, and Level 3 inputs have the lowest priority and include significant inputs that are generally less observable from objective sources. When available, the Company measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. The Company currently does not use Level 3 inputs to measure fair value.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 Fair Value Measurements

Debt — The Fixed Rate Notes and the Floating Rate Notes are actively traded in an established market. The fair values of these debt instruments are based on quotes obtained through financial information services and/or major financial institutions.

Level 2 Fair Value Measurements

Debt — The fair value of the Floating Rate Notes is estimated to approximate the carrying amount because the interest rates paid on such debt are generally set for periods of three months or less.

Oil and natural gas puts and collars — The fair values of some of the oil and natural gas puts and collars are estimated using similar, observable NYMEX published settlements.

(10) TROPICAL WEATHER

As a result of Hurricanes Katrina and Rita and three other hurricanes that traversed the Gulf of Mexico and adjacent land areas in 2005, nearly all of the Company’s production was shut in at one time or another during the third quarter of 2005 and into 2006. The Company maintained business interruption insurance during this period on its significant properties, including its East Bay field on which recovery of lost revenue continued to accrue until October 2006. Through March 31, 2007, the total business interruption claim on these fields was $62.6 million (all of which had been collected as of that date). In the first quarter of 2007, the Company settled and collected all remaining claims related to Hurricanes Katrina and Rita and recognized business interruption income of $9.1 million and a gain of $8.1 million on a property damage settlement.

(11) NEW ACCOUNTING PRONOUNCEMENTS

In March 2008, the FASB issued Statement of Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (Statement 161). Statement 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Statement 161 encourages, but does not require, comparative disclosures for earlier periods at initial adoption. The Company is currently assessing what impact Statement 161 may have on the Company’s financial position, results of operations or cash flows.

In December 2007, the FASB issued Statement of Accounting Standards No. 141R, “Business Combinations” (Statement 141R). Statement 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. Statement 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company is assessing what impact Statement 141R may have on its financial position, results of operations or cash flows should it complete a business combination after the effective date of Statement 141R.

(12) RELATED PARTY

One of the Company’s directors is a senior managing director of Evercore Partners, Inc. an affiliate of Evercore Group L.L.C. (Evercore). Evercore provided financial advisory services to the Company in connection with a subsequently terminated merger agreement in 2006 with Stone Energy Corporation, an unsolicited cash tender offer in 2006 by a U.S. Subsidiary of Woodside Petroleum, Ltd. that subsequently expired and the Company’s exploration of strategic alternatives. A $7.0 million fee was due to Evercore upon the earlier of the consummation of a transaction or September 5, 2007, of which $2.3 million was accrued during 2006 and the remaining $4.7 million was accrued in the first quarter of 2007 and paid in September 2007.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(13) SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

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

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Supplemental Condensed Consolidating Balance Sheet

As of March 31, 2008

	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13,845		$	—		$	—		$	13,845
Accounts receivable		34,401			6,023			2,140			42,564
Other current assets		3,682			131			—			3,813
Total current assets		51,928			6,154			2,140			60,222
Property and equipment		1,343,384			239,353			—			1,582,737
Less accumulated depreciation, depletion and amortization		(729,341	)		(123,609	)		—			(852,950	)
Net property and equipment		614,043			115,744			—			729,787
Investment in affiliates		80,635			116			(80,751	)		—
Notes receivable, long-term		—			115,531			(115,531	)		—
Other assets		25,574			90			—			25,664
	$	772,180		$	237,635		$	(194,142	)	$	815,673
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	124,035		$	1,170		$	—		$	125,205
Fair value of commodity derivative instruments		12,806			—			—			12,806
Total current liabilities		136,841			1,170			—			138,011
Long-term debt		474,501			115,531			(115,531	)		474,501
Other liabilities		54,666			42,323			—			96,989
		666,008			159,024			(115,531	)		709,501
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		442			98			(98	)		442
Additional paid-in capital		376,760			68			(68	)		376,760
Retained earnings (accumulated deficit)		(12,674	)		78,442			(78,442	)		(12,674	)
Treasury stock		(258,356	)		—			—			(258,356	)
Total stockholders’ equity		106,172			78,611			(78,611	)		106,172
	$	772,180		$	237,635		$	(194,142	)	$	815,673

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Supplemental Condensed Consolidated Statement of Operations

Three Months Ended March 31, 2008

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenue:
Oil and natural gas	$	75,131		$	22,324	$	—		$	97,455
Other		8,755			40		(8,754	)		41
		83,886			22,364		(8,754	)		97,496
Costs and expenses:
Lease operating		8,970			5,650		—			14,620
Exploration expenditures, dry hole costs and impairments		22,473			736		—			23,209
Depreciation, depletion, amortization and accretion		25,273			4,593		—			29,866
Taxes, other than on earnings		52			2,327		—			2,379
General and administrative		9,063			4,054		(3,750	)		9,367
Gain on sale of assets		(6,674	)		—		—			(6,674	)
Other expenses		1,096			—		—			1,096
Total costs and expenses		60,253			17,360		(3,750	)		73,863
Income from operations		23,633			5,004		(5,004	)		23,633
Other income (expense):
Interest expense, net		(11,611	)		—		—			(11,611	)
Gain (loss) on derivative instruments		(8,326	)		—		—			(8,326	)
		(19,937	)		—		—			(19,937	)
Income before income taxes		3,696			5,004		(5,004	)		3,696
Income taxes		(1,381	)		—		—			(1,381	)
Net income	$	2,315		$	5,004	$	(5,004	)	$	2,315

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Supplemental Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2008

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)
Net cash provided by operating activities	$	58,994		$	3,427		$	—	$	62,421
Cash flows used in investing activities:
Property acquisitions		(15,341	)		—			—		(15,341	)
Exploration and development expenditures		(43,583	)		(3,427	)		—		(47,010	)
Other property and equipment additions		(216	)		—			—		(216	)
Proceeds from sale of oil and natural gas assets		15,026			—			—		15,026
Net cash used in investing activities		(44,114	)		(3,427	)		—		(47,541	)
Cash flows used in financing activities:
Repayments of long-term debt		(35,000	)		—			—		(35,000	)
Proceeds from long-term debt		25,000			—			—		25,000
Exercise of stock options and warrants		101			—			—		101
Net cash used in financing activities		(9,899	)		—			—		(9,899	)
Net increase in cash and cash equivalents		4,981			—			—		4,981
Cash and cash equivalents at beginning of period		8,864			—			—		8,864
Cash and cash equivalents at end of period	$	13,845		$	—		$	—	$	13,845

(14) 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.

(15) RECLASSIFICATIONS

Certain reclassifications have been made to the prior period financial statements in order to conform to the classification adopted for reporting in fiscal 2008.

15

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

We were incorporated in January 1998 and operate in a single segment as an independent oil and natural gas exploration and production company. Our current operations are concentrated in the shallow to moderate depth waters in the Gulf of Mexico, focusing on the area from Ship Shoal in the west to our East Bay field in the east as well as the deepwater in depths less than 5,000 feet.

We continue to strive toward implementing our long-term growth strategy to increase our oil and natural gas reserves and production while focusing on reducing finding and development costs and operating costs to remain competitive with our industry peers. We are implementing this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential. We also evaluate acquisition opportunities including acquisitions in our core Central and Eastern offshore areas as a complement to the drilling and development activities we have budgeted for that area. We also consider strategic divestiture opportunities from time to time. Our drilling program is predominately comprised of moderate risk, higher or moderate reserve potential opportunities, as well as some high risk, higher reserve potential opportunities and low risk lower reserve potential opportunities, in order to achieve a balanced program of reserve 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, 2007 includes a discussion of our critical accounting policies, which have not changed significantly since the end of the last fiscal year.

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

We continue to generate prospects and strive to maintain an extensive inventory of drillable prospects in-house and we are being exposed to 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 projects. However, from time to time, we may use our bank credit facility to fund working capital needs as further discussed below.

On October 12, 2006 we announced that our Board of Directors (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. On March 12, 2007 we announced that the Board had concluded its strategic alternatives process. As a result of this process, the Board, with advice from our financial and legal advisors and management, determined to continue with the execution of our strategic plan, augmented by a self-tender offer for up to 8,700,000 of our common shares at $23.00 per share, the refinancing of our bank credit facility and a tender offer for all of our existing $150 million aggregate principal amount of senior notes due 2010 (the “Transactions”), and the divestment of selected properties following the completion of the Transactions to reduce debt under our new bank credit facility. We incurred $8.8 million of legal and financial advisory fees during the first quarter of 2007 related to the exploration of strategic alternatives and the tender offers.

On April 23, 2007 we refinanced our bank credit facility with a new $300 million revolving credit facility (the “bank credit facility”) with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the June 2007 sale of assets described below, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. At March 31, 2008, we had a borrowing base of $200 million (subsequently reduced to $150 million) and $20 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 on or about April 1 and October 1.

16

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

On May 4, 2007, we completed a cash tender offer for our $150 million 8.75% senior notes due 2010 (the “Senior Notes”). Approximately $145.5 million of these Senior Notes were repurchased and substantially all of their covenants have been removed.

On June 12, 2007, we completed the sale of substantially all of our onshore South Louisiana producing assets (the “June 2007 Sale”) for $68.6 million after giving effect to closing adjustments. We used the proceeds to pay down a portion of the bank credit facility. The estimated proved reserves of the disposed properties were approximately 2.1 Mmboe. The Company recorded a gain of $6.5 million on the sale.

On March 26 and 27, 2008, we completed the sale of two Gulf of Mexico Shelf properties located in our Western offshore area (the “March 2008 Sale”) for $15.0 million after giving effect to preliminary closing adjustments. The Company recorded a gain on the sale of $7.1 million.

We have included the results of operations from the dispositions through their respective closing dates. We have experienced a decrease in our production volumes as a result of the June 2007 Sale. For the foregoing reasons, these activities will affect the comparability of our historical results of operations with future periods.

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

As a result of Hurricanes Katrina and Rita and three other hurricanes that traversed the Gulf of Mexico and adjacent land areas in 2005, nearly all of the Company’s production was shut in at one time or another during the third quarter of 2005 and into 2006. We maintained business interruption insurance during this period on our significant properties, including our East Bay field on which recovery of lost revenue continued to accrue until October 2006. Through March 31, 2007, the total business interruption claim on these fields was $62.6 million (all of which had been collected as of that date). In the first quarter of 2007, we settled and collected all remaining claims related to Hurricanes Katrina and Rita and recognized business interruption income of $9.1 million and a gain of $8.1 million on a property damage settlement.

17

RESULTS OF OPERATIONS

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

	Three Months Ended March 31,
	2008			2007
Net production (per day):
Oil (Bbls)		6,432			9,244
Natural gas (Mcf)		56,202			100,427
Total barrels of oil equivalent (Boe)		15,799			25,982
Average sales prices, excluding impact of derivatives:
Oil (per Bbl)	$	93.24		$	53.31
Natural gas (per Mcf)		8.38			7.09
Total (per Boe)		67.78			46.36
Oil and natural gas revenues (in thousands):
Oil	$	54,575		$	44,348
Natural gas		42,880			64,054
Total		97,455			108,402
Impact of derivatives (1):
Oil (per Bbl)	$	(11.00	)	$	—
Natural gas (per Mcf)		(0.37	)		—
Average costs (per Boe):
Lease operating expense	$	9.89		$	7.16
Depreciation, depletion and amortization		20.04			20.49
Accretion expense		0.73			0.47
Taxes, other than on earnings		1.65			1.23
General and administrative		6.52			9.58
Increase (decrease) in oil and natural gas revenues between periods presented due to:
Changes in prices of oil	$	35,305
Changes in production volumes of oil		(25,078	)
Total increase in oil sales		10,227
Changes in prices of natural gas	$	11,380
Changes in production volumes of natural gas		(32,554	)
Total decrease in natural gas sales		(21,174	)

(1) Included in other income and expense in our three months ended March 31, 2008 statement of operations is an unrealized loss of $3.1 million due to the change in fair market value of contracts to be settled in the future and a loss of $5.2 million in contracts settled during the quarter. There was no impact from derivative contracts in the three months ended March 31, 2007.

18

REVENUES AND NET INCOME

Our oil and natural gas revenues decreased to $97.5 million in the first quarter of 2008 from $108.4 million in the first quarter of 2007. During the quarter, oil and natural gas prices increased but this increase was more than offset by natural reservoir declines combined with decreased oil and natural gas production due to the June 2007 Sale (a reduction of approximately 3,300 Boe per day) wells taken off production due to mechanical difficulties or facility requirements (a reduction of approximately 1,250 Boe per day), which was only partially offset by production from new wells.

We recognized net income of $2.3 million in the first quarter of 2008 compared to net income of $3.7 million in the first quarter of 2007. The overall change from period to period was primarily attributed to decreased oil and natural gas production primarily due to reasons discussed above, offset by increased oil and natural gas prices and changes in operating costs discussed below.

OPERATING EXPENSES

Operating expenses during the three month periods ended March 31, 2008 and 2007 were affected by the following:

• Lease operating expense (“Loe”) decreased to $14.2 million in the first quarter of 2008 compared with $16.7 million in the first quarter of 2007. This decrease is primarily a result of the June 2007 Sale discussed above offset by new wells coming on stream in new fields. On a per Boe basis, costs have increased due to decreased production volumes including production declines from existing fields with fixed costs.

• Taxes, other than on earnings, were $2.4 million in the first quarter of 2008 compared with $2.9 million in the first quarter of 2007. The decrease is due to lower production volumes within the state of Louisiana which is largely the result of the June 2007 Sale partially offset by increased commodity prices received. These taxes are expected to fluctuate from period to period depending on our remaining production volumes from non-federal leases and the commodity prices received.

• Exploration expenditures, including dry hole costs and impairments, increased to $23.2 million in the first quarter of 2008 from $21.8 million in the first quarter of 2007. The expense in the first quarter of 2008 is comprised of $21.7 million of costs for two exploratory wells or portions thereof which were found to be not commercially productive and $1.5 million of seismic expenditures and delay rentals. The expense in the first quarter of 2007 was comprised of $16.7 million of costs for four exploratory wells or portions thereof which were found to be not commercially productive and $5.1 million of seismic expenditures and delay rentals.

Our exploration expenditures, including dry hole charges, will vary depending on the amount of our capital budget dedicated to exploration activities, the cost of services to drill wells and the level of success we achieve in exploratory drilling activities.

• Depreciation, depletion and amortization (“DD&A”) decreased to $28.8 million in the first quarter of 2008 from $47.9 million in the first quarter of 2007. This decrease was primarily due to the June 2007 Sale ($7.6 million) and decreased production volumes ($12.5 million). Some fields carry a higher burden than others; therefore, changes in the sources of our production will also directly impact this expense.

• General and administrative expenses decreased to $9.4 million in the first quarter of 2008 from $22.4 million in the first quarter of 2007. Included in this expense is stock based compensation of $1.6 million and $1.9 million in the first quarters of 2008 and 2007, respectively. This decrease was primarily due to decreased personnel costs of $4.5 million and $8.8 million of financial and legal advisory fees that were incurred during the first quarter of 2007 related to the exploration of strategic alternatives and the tender offers.

OTHER INCOME AND EXPENSE

Interest expense increased to $11.9 million in the first quarter of 2008 from $6.8 million in the first quarter of 2007. The increase was primarily attributable to the net increase in the average borrowings due to the issuance of $450 million in aggregate principal amount of Senior Unsecured Notes in April 2007 combined with borrowings on our bank credit facility offset by the repurchase of $145.5 million in aggregate principal amount of the $150 million Senior Notes completed in May 2007.

19

LIQUIDITY AND CAPITAL RESOURCES

Our cash flows from operations totaled $62.4 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, 2008 was $13.8 million. Our future internally generated cash flows will depend on our ability to maintain production and offset production declines in producing fields through our exploration and development program and through acquisitions, as well as the prices of oil and natural gas. We may from time to time use the availability under our bank credit facility to balance working capital needs. We intend to use excess cash flow to repay borrowings on our bank credit facility.

On April 23, 2007 we completed a refinancing of our then existing revolving credit facility with the new $300 million bank credit facility with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the June 2007 Sale, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. The bank credit facility is secured by substantially all of our assets. The bank credit facility permits both prime rate borrowings and London InterBank Offered Rate (“LIBOR”) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank credit facility. The spread can range from 1.00% to 2.5% above LIBOR and 0% to 0.50% above prime. In addition we pay an annual fee on the unused portion of the bank credit facility ranging between 0.25% to 0.50%, based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require us to: (i) maintain a minimum current ratio, as defined by our bank credit facility, of 1.0x, (ii) maintain a minimum Consolidated EBITDAX to interest ratio, as defined by our bank credit facility, of 2.5x, and (iii) maintain a ratio of long-term debt to Consolidated EBITDAX below 3.5x, which decreased to 3.0x on April 1, 2008. As of May 6, 2008, we had a borrowing base of $150 million, $25 million outstanding and $125 million available under our bank credit facility. We were in compliance with the bank credit facility covenants as of March 31, 2008.

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

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

Net cash of $47.5 million used in investing activities in the first three months of 2008 consisted primarily of oil and natural gas exploration and development expenditures and lease purchases, offset by proceeds from the March 2008 Sale. Dry hole costs resulting from exploration expenditures are excluded from operating cash flows and included in investing activities. During the first three months of 2008, we completed four drilling operations, three of which were successful, and three recompletion/workover operations two of which were successful. During the first three months of 2007, we completed 10 drilling operations, 6 of which were successful, and 10 recompletion/workover operations, 9 of which were successful.

Our 2008 capital exploration and development budget is focused on moderate risk exploratory activities on undeveloped leases and our proved properties, combined with low risk 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. Our capital exploration and development budget for 2008 is currently approved for up to $200 million. During the first three months of 2008, capital expenditures were $65.0 million. The level of our capital exploration and development budget is based on many factors, including results of our drilling program, oil and natural gas prices, availability of cash flow, 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, our 2008 capital exploration and development budget may change.

20

In the June 2007 Sale, we sold substantially all of our onshore South Louisiana assets for $68.6 million in cash after closing adjustments. We used the proceeds to pay down a portion of our bank credit facility. In addition, in the March 2008 Sale, we sold of two Gulf of Mexico Shelf properties located in our Western offshore area for $15.0 million after preliminary closing adjustments.

We currently have on file a universal shelf registration statement which allows us to issue an aggregate of $300 million in common stock, preferred stock, senior debt and subordinated debt in one or more separate offerings with a size, price and terms to be determined at the time of sale. We have no immediate plans to enter into transactions under this registration statement, but would use the proceeds of any future offering under this registration statement for general corporate purposes, which may include debt repayment, acquisitions, expansion and working capital.

We have experienced and expect to continue to experience substantial working capital requirements, primarily due to our active exploration and developement program. We had a working capital deficit at March 31, 2008 and December 31, 2007 of $77.8 million and $61.5 million, respectively. Working capital deficits are not unusual, and are usually the result of increased accounts payable and accrued expenses related to ongoing exploration and development activity which are capitalized as non current assets. We believe that our working capital balance should be viewed in conjunction with the availability of borrowings under our bank credit facility when measuring liquidity. As of May 6, 2008 our borrowing base was reduced from $200 million to $150 million as a result of the reduction in our proved reserves which was impacted by our failure to replace reserves through drilling and the negative reserve revisions taken at the end of 2007.

Given our reduced exploration and development budget for 2008 and sustained high commodity prices, we continue to believe that internally generated cash flows combined with temporary borrowings under our bank credit facility will be sufficient to meet our budgeted capital requirements for at least the next twelve months. Availability under the bank credit facility may be used to balance short-term fluctuations in working capital requirements. We may use excess available cash flow to reduce our outstanding borrowings, including the redemption when permitted or the repurchase in the marketplace or in privately negotiated transactions of Senior Unsecured Notes; however, additional financing may be required in the future to fund our growth, including acquisitions for which we do not budget.

Our Annual Report on Form 10-K for the year ended December 31, 2007 included a discussion of our contractual obligations. 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 2007, the FASB issued Statement of Accounting Standards No. 141R, “Business Combinations” (“Statement 141R”). Statement 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. Statement 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We are assessing what impact Statement 141R may have on our financial position, results of operations or cash flows should we complete a business combination after the effective date of Statement 141R.

In March 2008, the FASB issued Statement of Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (Statement 161). Statement 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Statement 161 encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We are currently assessing what impact Statement 161 may have on our financial position, results of operations or cash flows.

21

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

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

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

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

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

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

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

• impact of oil and natural gas price fluctuations;

• the effects of competition;

• the success of our risk management activities;

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

• the impact of current and future laws and governmental regulations;

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

• general economic, market or business conditions.

All written and oral forward-looking statements attributable to us or persons acting on behalf of us are expressly qualified in their entirety by such factors. We refer you specifically to the section “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007. 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 and Floating Rate Notes. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. At March 31, 2008, $170 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 2008, interest rates for the period on variable rate debt outstanding during the period would have increased, and net income before income taxes would have decreased, by approximately $0.5 million based on total variable debt outstanding during the period. If market interest rates had averaged 1% lower in the first quarter of 2008, interest expense for the period on variable rate debt would have decreased, and net income before income taxes would have increased, by approximately $0.5 million.

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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, 2008, we had the following derivative contracts in place:

Natural Gas Positions
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Volume (Mmbtu)
			Daily	Total
04/08 – 06/08	Collar	$6.50/$11.15	20,000	1,820,000
11/08 – 12/08	Collar	$6.82/$15.38	20,000	1,220,000
01/09 – 03/09	Collar	$6.75/$17.15	10,000	900,000
Crude Oil Positions
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)	Volume (Bbls)
			Daily	Total
04/08 – 06/08	Collar	$55.00/$85.79	3,000	273,000
07/08 – 9/08	Put	$55.00	2,000	184,000
07/08 – 10/08	Collar	$55.00/$85.65	500	61,500
11/08 – 12/08	Collar	$55.00/$86.80	2,500	152,500
1/09 – 06/09	Collar	$55.00/$87.17	3,000	543,000

Volumes covered under these contracts, as of March 31, 2008, approximated 23% of our estimated production from proved reserves for the balance of the terms of the contracts. As of April 2, 2007, we elected to discontinue hedge accounting and therefore, not to designate any commodity derivative contracts as cash flow hedges under Statement 133. All derivative contracts are carried at their fair value on the consolidated balance sheet as assets or liabilities. Accordingly, we recognize all unrealized and realized gains and losses related to these contracts in the statement of operations as income or expense.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil and natural gas may have on the fair value of our derivative instruments. At March 31, 2008, the potential change in the fair value of commodity derivative instruments for the remainder of the contract terms assuming a 10% increase in the underlying commodity price was a $8.6 million negative impact on pre-tax income.

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 and the principal financial officer, we continue to evaluate 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 and principal financial officer concluded that the disclosure controls and procedures were effective as of the end of and during the period covered by this report with respect to information being recorded, processed, summarized and reported within time periods specified in the Commission’s rules and forms and with respect to timely communication to them and other members of management responsible for preparing periodic reports of 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, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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 and principal financial officer have concluded, based on their evaluation as of the end of and during the period, that our disclosure controls and procedures were effective to provide reasonable assurance that the objectives of our disclosure controls system were met.

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Item 6. EXHIBITS

Exhibits:
10.1*	Form of Cash-Settled Share Appreciation Right Grant under the Energy Partners, Ltd. 2006 Long Term Stock Incentive Plan.
10.2*	Second Amendment to Energy Partners, Ltd. Change of Control Severance Plan.
31.1*	Rule 13a-14(a)/15d-14(a) Certification of Chairman and Chief Executive Officer of Energy Partners, Ltd.
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Executive Vice President and Chief Financial Officer of Energy Partners, Ltd.
32.0*	Section 1350 Certification

* filed herewith

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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 8, 2008	By:	/s/ Joseph T. Leary
		Joseph T. Leary
		Executive Vice President and Chief Financial Officer
		(authorized officer and principal financial officer)

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EXHIBIT INDEX

Exhibits:
10.1*	Form of Cash-Settled Share Appreciation Right Grant under the Energy Partners, Ltd. 2006 Long Term Stock Incentive Plan.
10.2*	Second Amendment to Energy Partners, Ltd. Change of Control Severance Plan.
31.1*	Rule 13a-14(a)/15d-14(a) Certification of Chairman and Chief Executive Officer of Energy Partners, Ltd.
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Executive Vice President and Chief Financial Officer of Energy Partners, Ltd.
32.0*	Section 1350 Certification

* Filed herewith

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