Edgar Filing: ENERGY PARTNERS LTD

Form 10-Q for period ending March 31, 2007

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2007

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

Commission file number 001-16179

ENERGY PARTNERS, LTD.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

72-1409562

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer

Identification Number)


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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of May 1, 2007, there were 31,676,144 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, 2007 and December 31, 2006	3

	Consolidated Statements of Operations for the three months ended March 31, 2007 and 2006	4

	Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and 2006	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	24

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	25

Item 1A.	Risk Factors	25

Item 6.	Exhibits	26

Item 1.

FINANCIAL STATEMENTS

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	March 31, 2007			December 31, 2006
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	33,912		$	3,214
Trade accounts receivable		70,314			74,132
Other receivables		2,263			58,269
Deferred tax assets		1,499			1,387
Prepaid expenses		3,682			3,570

Total current assets		111,670			140,572
Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties		1,608,002			1,527,304
Less accumulated depreciation, depletion and amortization		(739,267	)		(680,845	)

Net property and equipment		868,735			846,459
Other assets		13,181			13,029
Deferred financing costs—net of accumulated amortization of $6,536 in 2007 and $6,302 in 2006		3,551			3,785

	$	997,137		$	1,003,845


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	34,981		$	47,154
Accrued expenses		133,156			133,198
Fair value of commodity derivative instruments		2,284			1,552

Total current liabilities		170,421			181,904
Long-term debt		315,000			317,000
Deferred tax liabilities		64,363			62,451
Asset retirement obligation		68,226			68,767
Other		1,584			1,453

		619,594			631,575

Stockholders’ equity:
Preferred stock, $1 par value. Authorized 1,700,000 shares; no shares issued and outstanding		—			—
Common stock, par value $0.01 per share. Authorized 100,000,000 shares; issued and outstanding: 2007—43,840,166 shares; 2006—42,501,726 shares		439			425
Additional paid-in capital		367,345			365,313
Accumulated other comprehensive loss—net of deferred taxes of $822 in 2007 and $558 in 2006		(1,464	)		(994	)
Retained earnings		68,663			64,966
Treasury stock, at cost. 2007—3,480,181 shares; 2006—3,479,814 shares		(57,440	)		(57,440	)

Total stockholders’ equity		377,543			372,270
Commitments and contingencies

	$	997,137		$	1,003,845

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(In thousands, except per share data)


	Three Months Ended March 31,
	2007			2006
Revenue:
Oil and natural gas	$	108,402		$	109,124
Other		61			69

		108,463			109,193

Costs and expenses:
Lease operating		16,749			12,365
Transportation expense		459			248
Taxes, other than on earnings		2,870			2,995
Exploration expenditures, dry hole costs and impairments		21,801			19,596
Depreciation, depletion and amortization		47,920			46,052
Accretion		1,100			1,093
General and administrative		22,395			12,456
Gain on insurance recoveries		(8,084	)		—
Other		—			(925	)

Total costs and expenses		105,210			93,880

Business interruption recovery		9,084			12,689
Income from operations		12,337			28,002

Other income (expense):
Interest income		180			279
Interest expense		(6,757	)		(5,084	)

		(6,577	)		(4,805	)

Income before income taxes		5,760			23,197
Income taxes		(2,064	)		(8,394	)

Net income		3,696			14,803

Basic earnings per share	$	0.09		$	0.39

Diluted earnings per share	$	0.09		$	0.37

Weighted average common shares used in Computing earnings per share:
Basic		40,157			38,028
Incremental common shares
Stock options		91			336
Warrants		58			1,899
Restricted share units		177			92
Performance shares		—			13

Diluted		40,483			40,368

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(In thousands)


	Three Months Ended March 31,
	2007			2006
Cash flows from operating activities:
Net income	$	3,696		$	14,803
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		49,021			47,145
Non cash-based compensation		2,139			2,115
Deferred income taxes		2,063			8,677
Exploration expenditures		16,663			13,968
Amortization of deferred financing costs		234			249
Gain on insurance recoveries		(8,084	)		—
Other		379			294
Changes in operating assets and liabilities:
Trade accounts receivable		3,818			11,381
Other receivables		56,006			(12,603	)
Prepaid expenses		(112	)		2,124
Other assets		(152	)		850
Accounts payable and accrued expenses		(11,843	)		(25,030	)
Other liabilities		(38	)		(103	)

Net cash provided by operating activities		113,790			63,870

Cash flows used in investing activities:
Acquisition of business, net of cash acquired		—			(420	)
Insurance recoveries for property, plant and equipment		19,574			—
Property acquisitions		(1,131	)		(7,872	)
Exploration and development expenditures		(100,070	)		(49,394	)
Other property and equipment additions		(159	)		(171	)

Net cash used in investing activities		(81,786	)		(57,857	)

Cash flows used in financing activities:
Repayments of long-term debt		(60,000	)		(30,109	)
Proceeds from long-term debt		58,000			20,000
Exercise of stock options and warrants		694			32

Net cash used in financing activities		(1,306	)		(10,077	)

Net increase (decrease) in cash and cash equivalents		30,698			(4,064	)
Cash and cash equivalents at beginning of period		3,214			6,789

Cash and cash equivalents at end of period	$	33,912		$	2,725

See accompanying notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) BASIS OF PRESENTATION

Certain information and footnote disclosures normally in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to rules and regulations of the Securities and Exchange Commission; however, management believes the disclosures which are made are adequate to make the information presented not misleading. These financial statements and footnotes should be read in conjunction with the financial statements and notes thereto included in Energy Partners, Ltd.’s (the Company) Annual Report on Form 10-K for the year ended December 31, 2006 and Management’s Discussion and Analysis of Financial Condition and Results of Operations. The Company maintains a website at www.eplweb.com which contains information about the Company including links to the Company’s Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K. The Company’s website and the information contained in it and connected to it shall not be deemed incorporated by reference into this report on Form 10-Q.

The financial information as of March 31, 2007 and for the three month periods ended March 31, 2007 and 2006 has not been audited. However, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to present fairly the results of operations for the periods presented have been included therein. The results of operations for the first three months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

(2) MERGERS AND ACQUISITIONS

On June 22, 2006, the Company entered into an agreement and plan of merger (the Merger Agreement) with Stone Energy Corporation (Stone), pursuant to which EPL Acquisition Corp. LLC, a wholly-owned subsidiary of the Company, would acquire all of the shares of Stone for a combination of cash and stock valued at approximately $2.1 billion. Prior to entering into the Merger Agreement, Stone terminated its then existing merger agreement with Plains Exploration and Production Company (Plains) on the same day. As required under the terms of the terminated merger agreement between Stone and Plains, Plains was entitled to a termination fee of $43.5 million, which was advanced by the Company to Plains and was included in other assets in the Consolidated Balance Sheet at June 30, 2006. On August 28, 2006, Woodside Petroleum, Ltd. (Woodside) announced its intention to commence a tender offer, through its U.S. subsidiary ATS Inc., for all of the Company’s outstanding shares of common stock for $23.00 per share subject to, among other conditions, the Company’s stockholders voting down the proposed Stone acquisition. The tender offer was commenced on August 31, 2006. On September 14, 2006, the Company announced that, on September 13, 2006, the Company’s board of directors (the Board) rejected as inadequate the unsolicited conditional offer by Woodside and recommended that its stockholders not tender their shares. On October 12, 2006 the Company announced that it had terminated the Merger Agreement with Stone and that the Board had directed the Company, assisted by its financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of the Company. In conjunction with the termination of the Merger Agreement, the Company paid to Stone $8.0 million, which was included in general and administrative expenses in the fourth quarter of 2006. In addition, the $43.5 million termination fee that was advanced to Plains in June 2006 on behalf of Stone was also expensed during 2006 along with other merger and strategic alternatives related costs of $15.0 million.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

In connection with an acquisition in 2002, the Company issued warrants to purchase four million shares of the Company’s common stock. Of the warrants, one million had a strike price of $9.00 and three million had a strike price of $11.00 per share. The warrants became exercisable on January 15, 2003 and expired on January 15, 2007. All remaining warrants were converted in the first quarter of 2007 and there were no warrants outstanding as of March 31, 2007.

In addition, former preferred stockholders of the acquired company had the right to receive contingent consideration based upon a percentage of the amount by which the before tax net present value of proved reserves related, in general, to exploratory prospect acreage held by the acquired company as of the closing date of the acquisition (the Ring-Fenced Properties) exceeded the net present value discounted at 30%. The potential consideration was determined annually from March 3, 2003 until March 1, 2007. The cumulative percentage remitted to the participants was 20% for the March 3, 2003, 30% for the March 1, 2004, 35% for the March 1, 2005, 40% for the March 1, 2006 and 50% for the March 1, 2007 determination dates. The contingent consideration, could have been paid in the Company’s common stock or cash at the Company’s option (with a minimum of 20% in cash) and in no event could exceed a value of $50 million. The Company capitalized, as additional purchase price, all contingent consideration payments all of which were made in cash. As of March 1, 2007 the Company determined that no final payment was due.

(3) EARNINGS PER SHARE

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

(4) HEDGING ACTIVITIES

The Company enters into hedging transactions with major financial institutions and others 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.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

The Company had the following hedging contracts as of March 31, 2007:

Natural Gas Positions


	Contract Type	Strike Price ($/Mmbtu)	Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Daily	Total
04/07 – 12/07	Collar	$5.00/$8.00	10,000	2,750,000

The Company entered into the following hedging contracts during the period from April 1, 2007 to April 30, 2007:

Natural Gas Positions
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)	Daily	Total
07/07 – 09/07	Collar	$7.00/$9.40	30,000	2,760,000
08/07 – 10/07	Put	$6.75	30,000	2,760,000
11/07	Collar	$7.25/$12.63	20,000	600,000
12/07 – 03/08	Collar	$6.93/$16.83	35,000	4,270,000
04/08 – 06/08	Collar	$6.50/$11.15	20,000	1,820,000
11/08 – 12/08	Collar	$6.82/$15.38	20,000	1,220,000
01/09 – 03/09	Collar	$6.75/$17.15	10,000	900,000

Crude Oil Positions
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)	Volume (Bbls)
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)	Daily	Total
07/07	Collar	$55.00/$82.00	1,500	46,500
08/07 – 10/07	Collar	$55.00/$84.00	500	46,000
11/07 – 12/07	Collar	$55.00/$83.13	3,000	183,000
01/08 – 06/08	Collar	$55.00/$84.25	2,500	455,000
07/08 – 10/08	Collar	$55.00/$85.65	500	61,500
11/08 – 06/09	Collar	$55.00/$86.25	1,000	242,000

Settlements of hedging contracts did not impact crude oil or natural gas revenues in the three months ended March 31, 2007. As of March 31, 2007, the Company’s derivative commodity instruments continued to qualify for hedge accounting treatment, and therefore, the Company has not reclassified any gains or losses into earnings in the periods presented. However, subsequent to March 31, 2007, the Company elected to discontinue hedge accounting and therefore, not to designate any commodity hedging contracts as cash flow hedges under Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Investments and Hedging Activities,” as Amended (Statement 133). All derivative contracts will be carried at their fair value on the consolidated balance sheet as assets or liabilities. The Company will begin recognizing all unrealized and realized gains and losses related to these contracts in the statement of operations as income or expense.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

The following tables reconcile the change in accumulated other comprehensive income for the three month periods ending March 31, 2007 and 2006.


	Three Months Ended March 31, 2007
	(in thousands)
Accumulated other comprehensive loss as of December 31, 2006—net of taxes of $558				$	(994	)
Net income	$	3,696
Other comprehensive income—net of tax
Hedging activities
Reclassification adjustments for settled contracts—net of taxes of $0		—
Changes in fair value of outstanding hedging positions—net of taxes of $264		(470	)

Total other comprehensive income		(470	)		(470	)

Comprehensive income	$	3,226

Accumulated other comprehensive loss as of March 31, 2007—net of taxes of $822				$	(1,464	)


	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	)

Based upon current prices, the Company expects to transfer approximately $2.3 million of pretax net deferred losses in accumulated other comprehensive loss as of March 31, 2007 to earnings during the next nine months when the forecasted transactions actually occur.

(5) OIL AND GAS PROPERTIES

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

(6) 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, 2007.


	Three Months Ended March 31, 2007
	(in thousands)
December 31, 2006	$	68,767
Accretion expense		1,100
Revisions		—
Liabilities incurred		—
Liabilities settled		(6	)

March 31, 2007	$	69,861

At March 31, 2007, and included above, asset retirement obligations required to be settled within the next twelve months of $1.6 million were included in accrued expenses on the Consolidated Balance Sheet.

(7) INDEBTEDNESS

On June 2, 2006, the Company amended and extended to May 31, 2011 its bank credit facility and increased its borrowing base from $150 million to $225 million, which was subsequently further increased to $250 million. At March 31, 2007, the Company had $165 million outstanding under the bank credit facility and $85 million available under its then current borrowing base of $250 million. The Company was in compliance with the bank credit facility covenants as of March 31, 2007.

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 all 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.

See note (15) for an update on the indebtedness of the Company subsequent to March 31, 2007.

(8) TROPICAL WEATHER

On August 29, 2005 Hurricane Katrina made landfall in the United States south of New Orleans causing catastrophic damage throughout portions of the Gulf of Mexico and to portions of Alabama, Louisiana and Mississippi, including New Orleans. As a result of the devastating effects of the storm on New Orleans and surrounding areas, the Company announced on August 30 that it had elected to establish temporary headquarters at its Houston, Texas office. A satellite office was also established in Baton Rouge, Louisiana.

On September 24, 2005 Hurricane Rita made landfall in the United States on the Texas/Louisiana border. This hurricane caused extensive damage throughout portions of the Gulf of Mexico region particularly to third-party infrastructure such as pipelines and processing plants.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

2007 exceeded repair costs incurred through March 31, 2007 by $3.2 million. Such amount has been deferred to offset hurricane repair expenses still to be incurred. Uninsured expenditures, if any, will be recorded to development costs or production costs as incurred, based on the nature of the expenditure. The timing of future repairs will be affected by equipment availability, design and repair planning and permitting.

(9) INCOME TAXES

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

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

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

(10) NEW ACCOUNTING PRONOUNCEMENTS

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

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

In February 2007, the FASB issued Statement of Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115” (Statement 159). Statement 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Statement 159 is expected to expand the use of fair value measurement, which is consistent with the Board’s long-term measurement objectives for accounting for financial instruments. Statement 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of Statement 157. The Company is assessing the impact of Statement 159 which is not currently expected to have an impact on the Company’s financial position, results of operations or cash flows.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

(11) RELATED PARTY

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

(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. See Note (15) for an update on the indebtedness of the Company subsequent to March 31, 2007. The following supplemental financial information sets forth, on a consolidating basis, the balance sheet, statement of operations and cash flow information for Energy Partners, Ltd. (Parent Company Only) and for the Guarantor Subsidiaries. The Company has not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries because management has determined that such information is not material to investors.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

Supplemental Condensed Consolidating Balance Sheet

As of March 31, 2007


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	33,912		$	—		$	—		$	33,912
Accounts receivable		72,432			145			—			72,577
Other current assets		3,346			1,835			—			5,181

Total current assets		109,690			1,980			—			111,670
Property and equipment		1,169,861			438,141			—			1,608,002
Less accumulated depreciation, depletion and amortization		(493,199	)		(246,068	)		—			(739,267	)

Net property and equipment		676,662			192,073			—			868,735
Investment in affiliates		151,125			204			(151,329	)		—
Notes receivable, long-term		—			221,909			(221,909	)		—
Other assets		16,753			(21	)		—			16,732

	$	954,230		$	416,145		$	(373,238	)	$	997,137

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	166,395		$	1,742		$	—		$	168,137
Fair value of commodity derivative instruments		2,284			—			—			2,284

Total current liabilities		168,679			1,742			—			170,421
Long-term debt		315,000			221,909			(221,909	)		315,000
Other liabilities		93,008			41,165			—			134,173

		576,687			264,816			(221,909	)		619,594
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		439			98			(98	)		439
Additional paid-in capital		367,345			310			(310	)		367,345
Accumulated other comprehensive loss		(1,464	)		—			—			(1,464	)
Retained earnings		68,663			150,918			(150,918	)		68,663
Treasury stock		(57,440	)		—			—			(57,440	)

Total stockholders’ equity		377,543			151,329			(151,329	)		377,543

	$	954,230		$	416,145		$	(373,238	)	$	997,137

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

Supplemental Condensed Consolidated Statement of Operations

Three Months Ended March 31, 2007


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenue:
Oil and natural gas	$	82,430		$	25,972		$	—		$	108,402
Other		(1,778	)		53			1,786			61

		80,652			26,025			1,786			108,463
Costs and expenses:
Lease operating		7,661			9,547			—			17,208
Taxes, other than on earnings		146			2,724			—			2,870
Exploration expenditures		17,304			4,497			—			21,801
Depreciation, depletion and amortization		38,386			10,634			—			49,020
General and administrative		21,986			4,159			(3,750	)		22,395
Gain on insurance recoveries		(8,084	)		—			—			(8,084	)

Total costs and expenses		77,399			31,561			(3,750	)		105,210

Business interruption recovery		9,084			—			—			9,084
Income from operations		12,337			(5,536	)		5,536			12,337

Interest expense, net		(6,577	)		—			—			(6,577	)

Income before income taxes		5,760			(5,536	)		5,536			5,760
Income taxes		(2,064	)		—			—			(2,064	)

Net income	$	3,696		$	(5,536	)	$	5,536		$	3,696

Supplemental Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2007


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(in thousands)
Net cash provided by operating activities	$	108,472		$	5,318		$	—	$	113,790
Cash flows used in investing activities:
Insurance recoveries from property, plant and equipment		19,574			—			—		19,574
Property acquisitions		(707	)		(424	)		—		(1,131	)
Exploration and development expenditures		(95,176	)		(4,894	)		—		(100,070	)
Other property and equipment additions		(159	)		—			—		(159	)

Net cash used in investing activities		(76,468	)		(5,318	)		—		(81,786	)
Cash flows used in financing activities:
Repayments of long-term debt		(60,000	)		—			—		(60,000	)
Proceeds from long-term debt		58,000			—			—		58,000
Exercise of stock options and warrants		694			—			—		694

Net cash provided by financing activities		(1,306	)		—			—		(1,306	)

Net increase in cash and cash equivalents		30,698			—			—		30,698
Cash and cash equivalents at beginning of period		3,214			—			—		3,214

Cash and cash equivalents at end of period	$	33,912		$	—		$	—	$	33,912

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(UNAUDITED)

(13) CONTINGENCIES

On September 12, 2006, Thomas Farrington, a purported stockholder of the Company, filed a putative class action suit against the Company, all of the Company’s directors, EPL Acquisition Corp. LLC, and Stone in the Delaware Court (the Farrington Action). As amended on October 19, 2006, the complaint in the Farrington Action alleges that the Company’s directors breached their fiduciary duties by agreeing to the termination fee provisions in the Merger Agreement, adopting the sixth-month stockholders rights agreement, amending and extending coverage to all full time employees of its change of control severance arrangements, and paying a fee to Stone in connection with the termination of the Merger Agreement. Farrington also alleges that the Company’s directors have failed to adequately disclose material information relevant to the Company stockholders’ decision whether to accept the Tender Offer. Farrington seeks declaratory and injunctive relief as well as unspecified damages. On October 19, 2006, the Delaware Court denied a motion filed by Farrington seeking expedited consideration of these claims. The Company and the individual defendants believe the claims are without merit and intend to defend vigorously against those claims.

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

(14) RECLASSIFICATIONS

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

(15) SUBSEQUENT EVENTS

On March 12, 2007, the Company announced that its Board had concluded its strategic alternatives process. As a result of this process, the Board, with advice from its financial 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 to reduce debt under the Company’s new bank credit facility following completion of the Transactions. On April 23, 2007, the Company closed a private placement of $450 million of senior unsecured notes, consisting of $300 million aggregate principal amount of 9.75% Senior Notes due 2014 and $150 million aggregate principal amount of Senior Floating Rate Notes due 2013. The interest rate on the Senior Floating Rate Notes for a particular interest period will be an annual rate equal to the three-month LIBOR as determined on the related interest determination date plus 5.125%. Also on April 23, 2007, the Company replaced its bank credit facility with a new $300 million revolving credit facility with an initial availability of $225 million and a borrowing base of $200 million. The net proceeds from the senior notes offering and the new revolving credit facility were used to purchase 8,700,000 shares of the Company’s common stock for approximately $200.1 million, to purchase approximately $143.4 million in principal amount of its then outstanding existing Senior Notes, and to repay $160 million under its then existing bank credit facility.

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

We were incorporated in January 1998 and operate in a single segment as an independent oil and natural gas exploration and production company. Our current operations are concentrated in the Shelf and deepwater Gulf of Mexico as well as the Gulf Coast onshore region.

In the first three months of 2007 we continued to make progress 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 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. We also evaluate acquisition opportunities including acquisitions in our core focus area which includes the Gulf of Mexico and onshore Gulf Coast regions as a complement to the exploration and development activities we have budgeted for that area. Our drilling program 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, 2006, includes a discussion of our critical accounting policies, which have not changed significantly since the end of the fiscal year.

On June 22, 2006, we entered into an agreement and plan of merger (the “Merger Agreement”) with Stone Energy Corporation (“Stone”), pursuant to which EPL Acquisition Corp. LLC, a wholly-owned subsidiary, would acquire all of the shares of Stone for a combination of cash and stock valued at approximately $2.1 billion. Prior to entering into the Merger Agreement, Stone terminated its then existing merger agreement with Plains Exploration and Production Company (“Plains”) on the same day. As required under the terms of the terminated merger agreement between Stone and Plains, Plains was entitled to a termination fee of $43.5 million, which was advanced by us to Plains and was included in other assets in the Consolidated Balance Sheet at June 30, 2006. On August 28, 2006, Woodside Petroleum, Ltd. (“Woodside”) announced its intention to commence a tender offer, through its U.S. subsidiary ATS Inc., for all of our outstanding shares of common stock for $23.00 per share subject to, among other conditions, our stockholders voting down the proposed Stone acquisition. The tender offer was commenced on August 31, 2006. On September 14, 2006, we announced that, on September 13, 2006, our board of directors (the “Board”) rejected as inadequate the unsolicited conditional offer by Woodside and recommended that our stockholders not tender their shares. On October 12, 2006 we announced that we had terminated the Merger Agreement with Stone and that the Board had directed us, assisted by our financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of the Company. On March 12, 2007 we announced that we had not received a definitive offer to purchase the Company and that we intended to initiate a self-tender offer for 8,700,000 of our common shares, refinance our bank credit facility and repurchase our 8³/4% senior notes through a concurrent debt tender and consent solicitation offer (the “Transactions”). In order to fund the Transactions, we undertook a private offering of $450 million of senior unsecured notes and entered into a new bank credit facility. In addition, we announced our plans to divest selected properties the proceeds from which would be used to reduce debt following the completion of the Transactions. In conjunction with the termination of the Merger Agreement, we paid $8.0 million to Stone, which was included in general and administrative expenses in the fourth quarter of 2006. In addition, the $43.5 million termination fee that was advanced to Plains in June 2006 on behalf of Stone was expensed in 2006 along with other merger and strategic alternatives related costs of $15.0 million. We have incurred an additional $8.8 million of legal and financial advisory fees in the first quarter of 2007 related to the exploration of strategic alternatives and the tender offers. Woodside’s tender offer expired in November 2006.

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 three other hurricanes that traversed the Gulf of Mexico and adjacent land areas, nearly all of the Company’s production was shut in at one time or another during the third quarter of 2005 and into 2006. Through December 31, 2006, we had recorded $53.5 million for business interruption recoveries of which $32.9 million and $20.6 million were recorded in the statement of operations in 2006 and fourth quarter of 2005, respectively. An additional $9.1 million was recorded in the first quarter of 2007 upon the final settlement of the Hurricane Katrina claim.

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

We currently have an extensive inventory of drillable prospects in-house, we are generating more prospects internally and we are exploring new opportunities through relationships with industry partners. Our policy is to fund our exploration and development expenditures with internally generated cash flow, which allows us to preserve our balance sheet to finance acquisitions and other capital intensive projects that might result from exploration and development activities. However, from time to time, we may use our bank credit facility to fund working capital needs.

RESULTS OF OPERATIONS

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


	Three Months Ended March 31,
	2007			2006
Net production (per day):
Oil (Bbls)		9,244			7,185
Natural gas (Mcf)		100,427			94,833
Total barrels of oil equivalent (Boe)		25,982			22,991
Oil and natural gas revenues (in thousands):
Oil	$	44,348		$	38,253
Natural gas		64,054			70,871
Total		108,402			109,124
Average sales prices, net of hedging:
Oil (per Bbl)	$	53.31		$	59.16
Natural gas (per Mcf)		7.09			8.30
Total (per Boe)		46.36			52.74
Impact of hedging:
Oil (per Bbl)	$	—		$	—
Natural gas (per Mcf)		—			(0.11	)
Average costs (per Boe):
Lease operating expense	$	7.16		$	5.98
Taxes, other than on earnings		1.23			1.45
Depreciation, depletion and amortization		20.49			22.26
Increase in oil and natural gas revenues between periods presented (net of hedging) due to:
Changes in prices of oil	$	(3,782	)
Changes in production volumes of oil		9,877

Total increase in oil sales		6,095
Changes in prices of natural gas	$	(10,418	)
Changes in production volumes of natural gas		3,601

Total increase (decrease) in natural gas sales		(6,817	)

REVENUES AND NET INCOME

Our oil and natural gas revenues decreased to $108.4 million in the first quarter of 2007 from $109.1 million in the first quarter of 2006. The decrease in first quarter of 2007 was a result of a decrease in both oil and natural gas prices as well as natural reservoir declines offset by production levels fully restored from Tropical Weather related damage and production from new fields.

We recognized net income of $3.7 million in the first quarter of 2007 compared to net income of $14.8 million in the first quarter of 2007. The decrease was largely due to higher general and administrative expenses due to the expensing of legal and financial advisory costs associated with our process of exploring strategic alternatives and subsequent tender offers combined with the fluctuations discussed below. This decrease was partially offset by a gain of approximately $8.1 million that was recognized due to settlement of our insurance claim for Hurricane Rita that exceeded our insurance receivables.

OPERATING EXPENSES

Operating expenses during the three month periods ended March 31, 2007 and 2006 were affected by the following:

•

Lease operating expense (“LOE”) increased to $16.7 million in the first quarter of 2007 compared with $12.4 million in the first quarter of 2006. This increase is primarily a result of a general increase in production from new wells coming on stream in new fields, the restart of storm shut-in production combined with workover and pipeline repair costs.

•

Taxes, other than on earnings, decreased slightly to $2.9 million in the first quarter of 2007 from $3.0 million in the first quarter of 2006. 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 $21.8 million in the first quarter of 2007 from $19.6 million in the first quarter of 2006. The expense in the first quarter of 2007 is comprised of $16.7 million of costs for exploratory wells or portions thereof which were found to be not commercially productive and $5.1 million of seismic expenditures and delay rentals. The expense in the first quarter of 2006 was 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.

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”) increased to $47.9 million in the first quarter of 2007 from $46.1 million in the first quarter of 2006, however DD&A on a per BOE basis decreased. This decrease was, in part, the result of impairments in the fourth quarter of 2006 on fields that had high DD&A burdens combined with a higher production contribution from our fields with lower DD&A burdens. Some fields carry a higher burden than others and fields in which more recent exploration and development activity has taken place are starting to reflect the effect of rising costs of oilfield industry services and capital goods; therefore, changes in the sources of our production will directly impact this expense.

•

General and administrative expenses increased to $22.4 million in the first quarter of 2007 from $12.5 million in the first quarter of 2006. Included in this expense is stock based compensation of $1.9 million in both the first quarter of 2007 and 2006. The overall increase was primarily attributable to expensed legal and financial advisory costs of $8.8 million associated with our process of exploring strategic alternatives and subsequent tender offers.

OTHER INCOME AND EXPENSE

Interest expense increased to $6.8 million in the first quarter of 2007 from $5.1 million in the first quarter of 2006. The increase was a result of an increase in the average borrowings under our bank credit facility in the first quarter of 2007 compared to the same period in 2006.

LIQUIDITY AND CAPITAL RESOURCES

Our cash flows from operations totaled $113.8 million in the first three months of the year, which included a $56.0 million change in other receivables as a result of our insurance collections during the period. We intend to fund our exploration and development expenditures for the year 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, 2007 was $33.9 million. Our future internally generated cash flows will depend on our ability to maintain and increase production through our exploratory and development drilling program, as well as the prices we receive for oil and natural gas. However, from time to time, we use our bank credit facility to fund working capital needs.

As of March 31, 2007 our bank credit facility, as amended on June 2, 2006, consisted of a revolving line of credit with a group of banks available though May 31, 2011. The borrowing base under the bank credit facility was increased at that time to $225 million, which was subsequently further increased to $250 million. We were in compliance with our then existing bank credit facility covenants as of March 31, 2007.

On April 23, 2007 we completed a refinancing of our bank credit facility with a new $300 million revolving credit facility (the “new bank credit facility”) with an initial availability of $225 million and a borrowing base of $200.0 million. The borrowing base under the bank credit facility is secured by substantially all of our assets. The new bank credit facility permits both prime rate borrowings and London interbank offered rate (“LIBOR”) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank credit facility. The spread can range from 1.00% to 2.5% above LIBOR and 0% to 0.50% above prime. In addition we pay an annual fee on the unused portion of the bank credit facility ranging between 0.25% to 0.50% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require us to: (i) maintain a minimum current ratio, as defined by our bank credit facility, of 1.0x, (ii) maintain a minimum Consolidated EBITDAX to interest ratio, as defined by our bank credit facility, of 2.5x, and (iii) maintain a ratio of long-term debt to Consolidated EBITDAX below 3.5x, which decreases to 3.0x after April 1, 2008. On April 30, 2007 we borrowed $70.0 million under our new bank credit facility to fund a portion of the equity self-tender offer. As of May 2, 2007, we had $155.0 million available under our new bank credit facility.

At March 31, 2007, we had $150 million in principal amount of 8.75% senior notes due 2010 (the “Senior Notes”) outstanding. Approximately $143.4 million of these Senior Notes were repurchased on April 23, 2007 and substantially all of their covenants were removed. Also on April 23, 2007 we completed an offering of $450 million aggregate principal amount of senior unsecured notes (the “Senior Unsecured Notes”), consisting of $300 million aggregate principal amount of 9.75% Senior Notes due 2014, with interest payable semi-annually on April 15 and October 15 beginning on October 15, 2007, and $150 million aggregate principal amount of Senior Floating Rate Notes due 2013. The interest rate on the Senior Floating Rate Notes for a particular interest period will be an annual rate equal to the three-month LIBOR plus 5.125%. Interest on the Senior Floating Notes are payable quarterly on January 15, April 15, July 15 and October 15, beginning in July of 2007. We may redeem the Senior Unsecured Notes, in whole or in part, prior to their maturity at specific redemption prices including premiums ranging from 4.875% to 0% from 2011 to 2013 and thereafter for the Fixed Rate Notes and premiums ranging from 2% to 0% from 2008 to 2010 and thereafter for the Floating Rate Notes. The indenture governing the Senior Unsecured Notes contains covenants, including but not limited to, a covenant limiting the creation of liens securing indebtedness. The Senior Unsecured Notes are not subject to any sinking fund requirements.

Net cash of $81.8 million used in investing activities in the first three months of 2007 consisted primarily of oil and natural gas exploration and development expenditures offset by proceeds of $19.6 million from the settlement of our Hurricane Rita insurance claim. Dry hole costs resulting from exploration expenditures are excluded from operating cash flows and included in investing activities. 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. During the first three months of 2006, we completed 6 drilling operations, 5 of which were successful, and 10 recompletion/workover operations, all of which were successful.

Our 2007 capital exploration and development budget is focused on moderate risk and higher risk exploratory activities on undeveloped leases and our proved properties combined with exploitation and development activities on our proved properties, and does not include acquisitions. We continue to manage our portfolio in order to maintain an appropriate risk balance between low risk development and exploitation activities, moderate risk exploration opportunities and higher risk, higher potential exploration opportunities. Currently, our exploration and development budget for 2007 is $300.0 million. We do not budget for acquisitions. During the first three months of 2007, capital and exploration expenditures were approximately $103.2 million. The level of our capital and exploration expenditure budget is based on many factors, including results of our drilling program, oil and natural gas prices, industry conditions, participation by other working interest owners and the costs and availability of drilling rigs and other oilfield goods and services. Should actual conditions differ materially from expectations, some projects may be accelerated or deferred and, consequently, we may change our total 2007 capital expenditures.

As part of the plan announced by our Board on March 12, 2007, the Company is in the process of divesting selected properties that are non-strategic assets in South Louisiana and the Gulf of Mexico Shelf. The proceeds from these sales will be used to reduce debt under our new bank credit facility. The Board has also authorized an open market share repurchase program of up to $50.0 million through April 2008, subject to business and market conditions.

We have experienced and expect to continue to experience substantial working capital requirements, primarily due to our active capital expenditure program. We believe that internally generated cash flows combined with temporary borrowings from our bank credit facility will be sufficient to meet our budgeted capital requirements for at least the next twelve months. Availability under the bank credit facility may be used to balance short-term fluctuations in working capital requirements. However, additional financing may be required in the future to fund our growth.

Our annual report on Form 10-K for the year ended December 31, 2006 included a discussion of our contractual obligations. There have been no material changes to that disclosure during the first three months ended March 31, 2007. In addition, we do not maintain any off balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues and expenses, results of operations, liquidity, capital expenditures or capital resources.

NEW ACCOUNTING PRONOUNCEMENTS

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

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

In February 2007, the FASB issued Statement of Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115” (Statement 159). Statement 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Statement 159 is expected to expand the use of fair value measurement, which is consistent with the Board’s long-term measurement objectives for accounting for financial instruments. Statement 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of Statement 157. We are assessing the impact of Statement 159 which is not currently expected to have an impact on our financial position, results of operations or cash flows.

FORWARD LOOKING INFORMATION

All statements other than statements of historical fact contained in this Report on Form 10-Q (“Report”) and other periodic reports filed by us or under the Securities and Exchange Act of 1934 and other written or oral statements made by us or on behalf, are forward-looking statements. Forward-looking statements are subject to risks and uncertainties. Although we believe that in making such statements our expectations are based on reasonable assumptions, such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected.

Except for 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);

•

impact of oil and natural gas price fluctuations;

•

the effects of competition;

•

the success of our risk management activities;

•

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

•

the impact of current and future laws and governmental regulations;

•

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

•

general economic, market or business conditions.

All written and oral forward-looking statements attributable to us or persons acting on behalf of us are expressly qualified in their entirety by such factors. We refer you specifically to the section “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2006 and this Quarterly Report on Form 10-Q. Although we believe that the assumptions on which any forward-looking statements in this Report and other periodic reports filed by us are reasonable, no assurance can be given that such assumptions will prove correct. All forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under our bank credit facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. At March 31, 2007, $165.0 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 2007, interest rates for the period on variable rate debt outstanding during the period would have increased, and net income before income taxes would have decreased by approximately $0.5 million based on total variable debt outstanding during the period. If market interest rates had averaged 1% lower in the first quarter of 2007, interest expense for the period on variable rate debt would have decreased, and net income before income taxes would have increased by approximately $0.5 million.

COMMODITY PRICE RISK

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. For the periods presented we sold all of our oil and natural gas production under price sensitive or market price contracts.

We use derivative commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of March 31, 2007, we had the following contracts in place:

Natural Gas Positions


Remaining Contract Term	Contract Type	Strike Price ($/ Mmbtu)		Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/ Mmbtu)		Daily	Total
04/07 – 12/07	Collar	$	5.00/$8.00	10,000	2,750,000

The Company entered into the following hedging contracts during the period from April 1, 2007 to April 30, 2007:

Natural Gas Positions
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)		Volume (Mmbtu)
Remaining Contract Term	Contract Type	Strike Price ($/Mmbtu)		Daily	Total
07/07 – 09/07	Collar	$	7.00/$9.40	30,000	2,760,000
08/07 – 10/07	Put		$6.75	30,000	2,760,000
11/07	Collar	$	7.25/$12.63	20,000	600,000
12/07 – 03/08	Collar	$	6.93/$16.83	35,000	4,270,000
04/08 – 06/08	Collar	$	6.50/$11.15	20,000	1,820,000
11/08 – 12/08	Collar	$	6.82/$15.38	20,000	1,220,000
01/09 – 03/09	Collar	$	6.75/$17.15	10,000	900,000

Crude Oil Positions
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)		Volume (Bbls)
Remaining Contract Term	Contract Type	Strike Price ($/Bbl)		Daily	Total
07/07	Collar		$55.00/$82.00	1,500	46,500
08/07 – 10/07	Collar		$55.00/$84.00	500	46,000
11/07 – 12/07	Collar		$55.00/$83.13	3,000	183,000
01/08 – 06/08	Collar		$55.00/$84.25	2,500	455,000
07/08 – 10/08	Collar		$55.00/$85.65	500	61,500
11/08 – 06/09	Collar		$55.00/$86.25	1,000	242,000

Our hedged volume as of March 31, 2007 approximated 6% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at March 31, 2007, we estimate the pre-tax loss would have been $2.3 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, 2007, the potential change in the fair value of commodity derivative instruments assuming a 10% increase in the underlying commodity price was a $1.2 million increase in the combined estimated pre-tax loss.

For purposes of calculating the hypothetical change in fair value, the relevant variables are the type of commodity (crude oil or natural gas), the commodities futures prices and volatility of commodity prices. The hypothetical fair value is calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes.

As of March 31, 2007, our derivative commodity instruments continued to qualify for hedge accounting treatment, and therefore, we have not reclassified any gains or losses into earnings in the periods presented. However, subsequent to March 31, 2007, we have elected to discontinue hedge accounting and therefore, not to designate any commodity hedging contracts as cash flow hedges under Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Investments and Hedging Activities,” as Amended (“Statement 133”). All derivative contracts will be carried at their fair value on the consolidated balance sheet as assets or liabilities. We will begin recognizing all unrealized and realized gains and losses related to these contracts in the statement of operations as income or expense.

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, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and

instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Accordingly, our disclosure controls and procedures are designed to provide reasonable, not absolute, assurance that the objectives of our disclosure control system are met and, as set forth above, our principal executive officer, principal financial officer and principal accounting officer have concluded, based on their evaluation as of the end of and during the period, that our disclosure controls and procedures were effective.

Part II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

Item 1A.

RISK FACTORS

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

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

As of May 2, 2007, after giving effect to the sale of $450 million of senior unsecured notes and borrowings under our new bank credit facility, the proceeds of which were used to repurchase approximately $200.1 million of our common stock, to purchase approximately $143.4 million of our senior notes, and to refinance our revolving credit facility, we would have had total indebtedness of approximately $527.0 million. In addition, our interest expense will increase significantly. A significant portion of our indebtedness has a floating rate of interest, which may increase over time.

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

•

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

•

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

•

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

•

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

•

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

•

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

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

Item 6.

EXHIBITS


Exhibits:

10.1		Revolving Credit Facility, dated as of April 23, 2007, among Energy Partners, Ltd., the lenders party thereto and Bank of America, N.A., as Administrative Agent, L/C Issuer and Collateral Agent (incorporated by reference to Exhibit 10.2 of EPL’s Form 8-K filed April 26, 2007).

10.2		First Amendment to Energy Partners, Ltd. 2006 Long Term Stock Incentive Plan, dated March 21, 2007 (incorporated by reference to Exhibit 99.1 of EPL’s Form 8-K filed March 27, 2007).

10.3		Indenture, dated as of April 23, 2007, among Energy Partners, Ltd., certain subsidiaries thereof and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 of EPL’s Form 8-K filed April 26, 2007).

10.4		Registration Rights Agreement, dated as of April 23, 2007, among Energy Partners, Ltd., certain subsidiaries thereof and the Initial Purchasers listed therein (incorporated by reference to Exhibit 10.2 of EPL’s Form 8-K filed April 26, 2007).

10.5*		Form of Nonqualifed Stock Option Grant under the Energy Partners, Ltd. Amended and Restated 2006 Long-Term Stock Incentive Plan.

10.6*		Form of Restricted Share Unit Agreement under Energy Partners, Ltd. Amended and Restated 2006 Long-Term Stock Incentive 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 Certifications

*	filed herewith

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	ENERGY PARTNERS, LTD.

Date: May 3, 2007	By:	/s/ Timothy R. Woodall
		Timothy R. Woodall
		Executive Vice President and Chief Financial Officer
		(authorized officer and principal financial officer)

EXHIBIT INDEX


Exhibits:
10.1		Revolving Credit Facility, dated as of April 23, 2007, among Energy Partners, Ltd., the lenders party thereto and Bank of America, N.A., as Administrative Agent, L/C Issuer and Collateral Agent (incorporated by reference to Exhibit 10.2 of EPL’s Form 8-K filed April 26, 2007).

10.2		First Amendment to Energy Partners, Ltd. 2006 Long Term Stock Incentive Plan, dated March 21, 2007 (incorporated by reference to Exhibit 99.1 of EPL’s Form 8-K filed March 27, 2007).

10.3		Indenture, dated as of April 23, 2007, among Energy Partners, Ltd., certain subsidiaries thereof and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 of EPL’s Form 8-K filed April 26, 2007).

10.4		Registration Rights Agreement, dated as of April 23, 2007, among Energy Partners, Ltd., certain subsidiaries thereof and the Initial Purchasers listed therein (incorporated by reference to Exhibit 10.2 of EPL’s Form 8-K filed April 26, 2007).

10.5*		Form of Nonqualifed Stock Option Grant under the Energy Partners, Ltd. Amended and Restated 2006 Long-Term Stock Incentive Plan.

10.6*		Form of Restricted Share Unit Agreement under Energy Partners, Ltd. Amended and Restated 2006 Long-Term Stock Incentive 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 Certifications

*	Filed herewith

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