Edgar Filing: ENERGY PARTNERS LTD

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Amendment No.1 to Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

(Mark One)

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

For the quarterly period ended June 30, 2010

¨	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)

(504) 569-1875

(Registrant’s telephone number, including area code)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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 filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨

As of August 2, 2010, there were 40,090,810 shares of the Registrant’s Common Stock, par value $0.001 per share, outstanding.

EXPLANATORY NOTE

This Amendment No. 1 (this “Amendment”) amends the Quarterly Report on Form 10-Q for Energy Partners, Ltd. (the “Company”), originally filed with the Securities and Exchange Commission (the “SEC”) on August 5, 2010 (the “Original Filing”), solely for the purpose of adding the required signature of our principal financial officer.

Except as described above, no other changes have been made to the Original Filing. The Original Filing continues to speak as of the date of the Original Filing, and the Company has not updated the disclosures contained therein to reflect any events which occurred at a date subsequent to the filing of the Original Filing.

TABLE OF CONTENTS


		Page

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements:		3

Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2010 and December 31, 2009			3

Condensed Consolidated Statements of Operations (Unaudited) for the three and six months ended June 30, 2010 and 2009			4

Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended June 30, 2010 and 2009			5

Notes to Condensed Consolidated Financial Statements (Unaudited)			6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		10

Item 3.	Quantitative and Qualitative Disclosures about Market Risk		19

Item 4.	Controls and Procedures		19

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings		20

Item 1A.	Risk Factors		20

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		20

Item 3.	Defaults Upon Senior Securities		20

Item 5.	Other Information		20

Item 6.	Exhibits		21

PART I - FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


(In thousands, except share data)	June 30, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	28,188		$	26,745
Trade accounts receivable		23,709			27,958
Receivables from insurance		3,763			5,464
Fair value of commodity derivative instruments		507			914
Deferred tax assets		3,861			5,768
Prepaid expenses		3,770			2,940

Total current assets		63,798			69,789
Property and equipment — successful efforts method of accounting for oil and natural gas properties		675,869			648,517
Less accumulated depreciation, depletion and amortization		(104,978	)		(37,535	)

Net property and equipment		570,891			610,982
Restricted cash		11,140			22,147
Other assets		2,702			3,647
Deferred financing costs — net of accumulated amortization of $974 at June 30, 2010 and $325 at December 31, 2009		2,737			2,663

	$	651,268		$	709,228


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	17,718		$	14,047
Accrued expenses		33,742			32,822
Asset retirement obligations		7,575			10,830
Current portion of long-term debt		25,000			18,750
Fair value of commodity derivative instruments		4,551			10,256

Total current liabilities		88,586			86,705
Long-term debt		—			58,590
Asset retirement obligations		64,602			59,150
Deferred tax liabilities		15,330			16,953
Fair value of commodity derivative instruments		1,166			7,519
Other		20			224
Commitments and contingencies (Note 7)

		169,704			229,141
Stockholders’ equity:
Preferred stock, $0.001 par value per share. Authorized 1,000,000 shares; no shares issued and outstanding at June 30, 2010 and December 31, 2009		—			—
Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued and outstanding 40,090,810 and 40,021,770 at June 30, 2010 and December 31, 2009, respectively		40			40
Additional paid-in capital		502,030			501,059
Accumulated deficit		(20,506	)		(21,012	)

Total stockholders’ equity		481,564			480,087

	$	651,268		$	709,228

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Successor Company						Predecessor Company
(In thousands, except per share data)	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010			Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Revenue:
Oil and natural gas	$	58,163		$	128,846		$	45,861		$	88,511
Other		34			70			215			265

		58,197			128,916			46,076			88,776

Costs and expenses:
Lease operating		13,675			28,117			15,044			31,021
Transportation		312			802			293			429
Exploration expenditures and dry hole costs		783			2,637			746			1,318
Impairments		10,885			11,654			1,467			6,580
Depreciation, depletion and amortization		26,106			55,961			34,054			66,194
Accretion of liability for asset retirement obligations		3,222			6,444			1,843			3,677
General and administrative		4,875			9,063			7,584			16,873
Taxes, other than on earnings		2,276			4,313			1,376			2,775
Loss on abandonment activities		774			577			118			574
Other		(34	)		(86	)		100			(12	)

Total costs and expenses		62,874			119,482			62,625			129,429
Business interruption recovery		—			—			—			1,185

Income (loss) from operations		(4,677	)		9,434			(16,549	)		(39,468	)
Other income (expense):
Interest income		88			97			9			47
Interest expense (contractual interest of $11,028 and $22,741 for the three and six months ended June 30, 2009, respectively)		(3,945	)		(8,147	)		(4,524	)		(16,237	)
Gain (loss) on derivative instruments		6,957			5,033			(923	)		2,728
Loss on extinguishment of debt		(5,627	)		(5,627	)		—			—

		(2,527	)		(8,644	)		(5,438	)		(13,462	)

Income (loss) before reorganization items and income taxes		(7,204	)		790			(21,987	)		(52,930	)

Reorganization items		—			—			(11,674	)		(12,602	)


Income (loss) before income taxes		(7,204	)		790			(33,661	)		(65,532	)
Income taxes		2,594			(284	)		—			—

Net income (loss)		(4,610	)		506			(33,661	)		(65,532	)

Basic earnings (loss) per share	$	(0.12	)	$	0.01		$	(1.05	)	$	(2.04	)
Diluted earnings (loss) per share	$	(0.12	)	$	0.01		$	(1.05	)	$	(2.04	)
Weighted average common shares used in computing earnings (loss) per share:
Basic		40,057			40,049			32,206			32,156
Effect of dilutive stock options and restricted shares		—			31			—			—

Diluted		40,057			40,080			32,206			32,156

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


(In thousands)	Successor Company Six Months Ended June 30, 2010			Predecessor Company Six Months Ended June 30, 2009
Cash flows from operating activities:
Net income (loss)	$	506		$	(65,532	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		55,961			66,194
Accretion of liability for asset retirement obligations		6,444			3,677
Unrealized gain on derivative contracts		(11,316	)		—
Non cash compensation		739			2,266
Deferred income taxes		284			—
Repayment of PIK Notes issued for payment of in-kind interest		(3,395	)		—
Exploration expenditures		1,827			28
Impairments		11,654			6,580
Amortization of deferred financing costs and discount on debt		457			8,001
Loss on abandonment activities		577			574
Other		—			2
Changes in operating assets and liabilities:
Trade accounts receivable		4,249			8,365
Other receivables		1,701			1,544
Prepaid expenses		(830	)		1,126
Other assets		622			(128	)
Accounts payable and accrued expenses		3,003			(9,640	)
Other liabilities		(4,995	)		(13,897	)

Net cash provided by operating activities		67,488			9,160

Cash flows provided by (used in) investing activities:
Decrease in restricted cash		11,007			—
Property acquisitions		(615	)		(139	)
Exploration and development expenditures		(26,910	)		(27,456	)
Other property and equipment additions		(39	)		(129	)
Proceeds from sale of oil and gas assets		—			150

Net cash used in investing activities		(16,557	)		(27,574	)

Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		20,394			40,000
Repayments of indebtedness, excluding repayment of PIK Notes issued to pay interest of $3,395		(69,882	)		—

Net cash provided by (used in) financing activities		(49,488	)		40,000

Net increase in cash and cash equivalents		1,443			21,586
Cash and cash equivalents at beginning of period		26,745			1,991

Cash and cash equivalents at end of period	$	28,188		$	23,577

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Debt incurred to pay deferred financing costs		737			—

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) BASIS OF PRESENTATION

Energy Partners, Ltd. (“we,” “our,” “us,” or “the Company”) was incorporated as a Delaware corporation on January 29, 1998. We operate 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 state and federal waters offshore Louisiana.

On May 1, 2009, we and certain of our subsidiaries filed voluntary petitions (In re: Energy Partners, Ltd., et. al., Case No. 09-32957) for reorganization under Chapter 11 of Title 11 of the United States Code, 11 U.S.C. §§ 101 et seq., as amended (“Chapter 11”), in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). On September 21, 2009, we emerged from Chapter 11 reorganization (the “Exit Date”) pursuant to the plan of reorganization confirmed by the Bankruptcy Court (the “Plan”). In accordance with the Plan, the Company’s 9.75% Senior Unsecured Notes due 2014 (the “Fixed Rate Notes”), its Senior Floating Rate Notes due 2013 (the “Floating Rate Notes” and together with the Fixed Rate Notes, the “Senior Unsecured Notes”) and its 8.75% Senior Notes due 2010 (collectively with the Senior Unsecured Notes, the “Predecessor Company Notes”) and the related accrued interest were discharged in the reorganization. We converted the Predecessor Company Notes and outstanding Predecessor Company (as defined below) common stock into shares of our new common stock as of the Exit Date. In accordance with the terms of the Plan, the Predecessor Company Notes and related indentures, as well as the Predecessor Company’s outstanding common shares, were cancelled. Each holder of these notes received, in exchange for such holder’s respective claim (including principal and accrued interest), such holder’s pro rata portion of approximately 95% of the common stock in the Successor Company (as defined below), or 38 million shares. Each holder of the Predecessor Company’s common stock received, in full satisfaction of and in exchange for such holder’s respective common stock interests, such holder’s pro rata portion of approximately 5% of the common stock in the Successor Company, or approximately 2 million shares. Additional information regarding our reorganization under Chapter 11 is available in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (the “SEC”) on March 11, 2010 (the “2009 Annual Report”).

In accordance with Financial Accounting Standards Board Accounting Standards Codification (“ASC”) Topic 852 (“ASC 852”), “Reorganizations,” we adopted fresh-start accounting as of September 30, 2009. Fresh-start accounting is required upon a substantive change in control and requires that the reporting entity allocate the reorganization value of the Company to its assets and liabilities in relation to their fair values. Under the provisions of fresh-start accounting, a new entity has been deemed created for financial reporting purposes. References to the “Predecessor Company” refer to reporting dates of the Company through September 30, 2009, including the effect of the reorganization and application of fresh-start accounting; subsequent thereto, the Company is referred to as the “Successor Company” in the condensed consolidated statements of operations and cash flows and the notes to the condensed consolidated financial statements. The statements of operations for the three- and six-month periods ended June 30, 2009 and the statement of cash flows for the six-month period ended June 30, 2009 do not reflect the effect of any changes in the Company’s capital structure or changes in fair values of assets and liabilities as a result of fresh-start accounting.

The financial information as of June 30, 2010 and for the three- and six-month periods ended June 30, 2010 and June 30, 2009 has not been audited. However, in the opinion of management, all adjustments (which include only normal, recurring adjustments) necessary to present fairly the financial position and results of operations for the periods presented have been included therein. 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. The condensed consolidated balance sheet at December 31, 2009 has been derived from the audited financial statements at that date. Certain reclassifications have been made to the prior period financial statements in order to conform to the classification adopted for reporting in the current period. These financial statements and footnotes should be read in conjunction with the financial statements and notes thereto included in our 2009 Annual Report. The results of operations and cash flows for the first six months of the year are not necessarily indicative of the results of operations which might be expected for the entire year and the financial information presented for the Successor Company is not comparable to the financial information presented for the Predecessor Company.

(2) EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share includes the effect, if dilutive, of potential common shares associated with stock option and restricted share awards outstanding during each period.

(3) ASSET RETIREMENT OBLIGATIONS

Changes in our asset retirement obligations were as follows:


	Six Months Ended June 30, 2010
	(in thousands)
Balance at December 31, 2009	$	69,980
Accretion expense		6,444
Revisions		585
Liabilities settled		(4,832	)

Balance at June 30, 2010		72,177
Less: Amount required to be settled within the next twelve months		(7,575	)

Balance at June 30, 2010, noncurrent asset retirement obligations	$	64,602

(4) INDEBTEDNESS

Total indebtedness was as follows:


(In thousands)	June 30, 2010		December 31, 2009
Term loan component of Amended Credit Facility, interest rate of 7.5% on June 30, 2010, based on base rate plus a floating spread, payable in six equal monthly installments of principal from July 28, 2010 to December 28, 2010	$	25,000	$	—
Term loan component of Credit Facility, interest rate of 6.5% on December 31, 2009, based on base rate plus a floating spread, payable in twelve equal monthly installments of principal from October 21, 2009 to September 21, 2010		—		18,750
PIK Notes, face amount of $61.1 million, interest rate of 20%, payable September 21, 2014 (net of $5.9 million of unamortized original issue discount)		—		55,195
In-kind interest on PIK Notes (new notes issued January 1, 2010), face amount of $3.4 million, interest rate of 20%, payable September 21, 2014		—		3,395

Total indebtedness		25,000		77,340
Current portion of indebtedness		25,000		18,750

Noncurrent portion of indebtedness	$	—	$	58,590

On June 16, 2010, we entered into an amendment (the “First Amendment”) to our Credit Facility dated as of September 21, 2009, (the “Credit Facility”) (together with the First Amendment, the “Amended Credit Facility”) with General Electric Capital Corporation, as administrative agent (the “Agent”), and the lender parties thereto (the “Lenders”). Upon its effectiveness on June 28, 2010, the Amended Credit Facility established a $70 million borrowing base consisting of (a) a new $25 million term loan payable, with interest, in six equal monthly installments of principal from July 28, 2010 to December 28, 2010 and (b) a revolving credit facility with a three-year term that may be used for revolving credit loans and letters of credit up to an initial maximum principal amount of $45 million. The interest rate spread on loans and letters of credit under the Amended Credit Facility are based on the level of utilization and will range from 3.75% to 4.25% for base rate borrowings and 4.75% to 5.25% for LIBOR borrowings. The First Amendment contains the Lenders’ consent for us to redeem all outstanding principal and pay all accrued interest on our 20% Senior Subordinated Secured PIK Notes due 2014 (the “PIK Notes”), which redemption occurred on June 28, 2010 and was a condition to the effectiveness of the First Amendment.

The redemption price of the PIK Notes, all of which were redeemed, was 100% of the outstanding aggregate principal amount. In connection with the redemption, we paid a total of $70.9 million of principal and accrued interest. We recorded a loss on the redemption of $5.6 million representing the total of the unamortized original issue discount and unamortized deferred financing costs associated with the PIK Notes.

The First Amendment does not make any material changes to the covenants, default provisions or collateral requirements under the Credit Facility. Our obligations under the Amended Credit Facility and under derivative contracts are guaranteed by our material subsidiaries and secured by our real property assets and the oil and natural gas properties to which 90% of the present value of our proved reserves is attributable. The documentation for our Amended Credit Facility continues to provide security for our obligations arising from derivative contracts with a party who was previously a lender (the “Derivative Counterparty”) under the Credit Facility. Repayment of our term loan obligation to the Derivative Counterparty under the Credit Facility in connection with the execution of the First Amendment resulted in a “Collateral Event” as defined in the governing agreements applicable to the derivative contracts with the Derivative Counterparty. As a result, the Derivative Counterparty may request that we provide additional collateral reasonably satisfactory to the Derivative Counterparty, as described in the agreements governing this derivative transaction, as amended, by October 31, 2010. Alternatively, we may novate our derivative contracts prior to October 31, 2010. Should we fail to perform in accordance with the derivative transaction governing agreements, as amended, the Derivative Counterparty’s remedies may include liquidation of the derivative contracts, which could result in material cash payments the amount of which would depend on the fair values of the derivative contracts at that time. Our estimated fair value of the obligations under derivative contracts subject to the collateral requirements described above was $5.7 million as of June 30, 2010.

The borrowing base of $70 million under the Amended Credit Facility at June 30, 2010 includes the $25 million balance on the term loan. The maximum amount of letters of credit that may be outstanding at any one time is $20 million, and the amount available under the revolving credit facility is limited by the borrowing base. The borrowing base is subject to semi-annual redeterminations based on the proved reserves of the oil and natural gas properties that serve as collateral for the Amended Credit Facility. Monthly scheduled repayments of principal on the term loan, each in the amount of $4.2 million, reduce the borrowing base by the amount of such repayments.

(5) DERIVATIVE TRANSACTIONS

We enter into derivative transactions to reduce exposure to fluctuations in the price of oil and natural gas for a portion of our production. Our put contracts limit our exposure to declines in the sales price of oil for a limited amount of our production. Our fixed-price swaps fix the sales price for a limited amount of our production and, for the contracted volumes, eliminate our ability to benefit from increases in the sales price of the related production. Derivative contracts are carried at their fair value on the condensed consolidated balance sheets as Fair value of commodity derivative instruments and in Other assets, and all unrealized and realized gains and losses are recorded in Gain (loss) on derivative instruments in Other income (expense) in the condensed consolidated statements of operations.

As of June 30, 2010, the following derivative instruments were outstanding:

Oil Contracts


	Fixed-Price Swaps						Puts
Remaining Contract Term	Daily Average Volume (Bbls)		Volumes (Bbls)		Average Swap Price ($/Bbl)		Daily Average Volume (Bbls)		Volume (Bbls)		Floor Price ($/Bbl)
July 2010		2,700		83,700	$	68.84		503		15,600	$	60.00
August 2010—November 2010		625		76,200	$	69.65		1,673		204,150	$	60.00
December 2010		1,200		37,200	$	70.37		1,302		40,350	$	60.00
January 2011—July 2011		2,261		479,250	$	71.13		502		106,500	$	60.00
August 2011—November 2011		502		61,200	$	72.18		1,301		158,700	$	60.00
December 2011		948		29,400	$	72.64		1,302		40,350	$	60.00

All of our commodity derivative instruments are with the Derivative Counterparty, as further described in Note 4. See Note 4 for information regarding collateral requirements related to our derivative instruments.

The following table presents information about the components of gain (loss) on derivative instruments:


	Successor Company						Predecessor Company
	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
	2010			2010			2009			2009
	(in thousands)
Derivative contracts:
Unrealized gain due to change in fair market value	$	9,580		$	11,316		$	—		$	—
Realized gain (loss) on settlement		(2,623	)		(6,283	)		(923	)		2,728

Total gain (loss) on derivative instruments	$	6,957		$	5,033		$	(923	)	$	2,728

(6) FAIR VALUE MEASUREMENTS

ASC Topic 820, “Fair Value Measurements and Disclosures,” establishes a fair value hierarchy with three levels based on the reliability of the inputs used to determine fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets and liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of June 30, 2010, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, primarily our commodity derivative instruments. The fair values of derivative instruments were measured using price inputs published by NYMEX. These price inputs are quoted prices for assets and liabilities similar to those held by us and meet the definition of Level 2 inputs within the fair value hierarchy. The following table presents our assets and liabilities that are measured at fair value on a recurring basis:


	As of June 30, 2010
							Fair Value Measurements Using:
	Carrying Amount			Total Fair Value			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Financial Assets (Liabilities) (in thousands):
Derivative instruments	$	1,399		$	1,399		$	—	$	1,399		$	—
Derivative instruments	$	(5,717	)	$	(5,717	)	$	—	$	(5,717	)	$	—

The fair value of our variable rate debt under our Amended Credit Facility approximated the carrying amount at June 30, 2010.

On June 29, 2010, we entered into a wind storm agreement with an insurance company. Under this agreement, if a named wind storm occurs in a specified area of the Gulf of Mexico and that storm meets certain strength criteria, the insurance company will pay cash proceeds to us of $6.9 million. We paid a premium of $0.9 million for this agreement, and the agreement terminates in December 2010. This wind storm agreement is considered a weather derivative under the applicable authoritative guidance related to financial instruments. We recognized the premium paid as a current asset which will be amortized to expense over the six-month term of the agreement. At June 30, 2010, we estimate that the fair value of this financial instrument approximates the amount of the premium paid.

We evaluate our capitalized costs of proved oil and natural gas properties for potential impairment when circumstances indicate that the carrying values may not be recoverable. Our assessment of possible impairment of proved oil and natural gas properties is based on our best estimate of future prices, costs and expected net future cash flows by property (generally analogous to a field or a lease). An impairment loss is indicated if estimated undiscounted net future cash flows are less than the carrying value of a property. The impairment expense is measured as the shortfall between the net book value of the property and its estimated fair value measured based on the discounted net future cash flows from the property. The inputs used to estimate the fair value of our oil and natural gas properties meet the definition of Level 3 inputs within the fair value hierarchy. Impairment expense for the three- and six-month periods ended June 30, 2010 was primarily related to two producing fields which were determined to have future net cash flows less than their carrying values due primarily to reservoir performance resulting in the write down of these properties to their estimated fair values as of June 30, 2010.

(7) COMMITMENTS AND CONTINGENCIES

We maintain restricted escrow funds in a trust for future plugging, abandonment and other decommissioning costs at our East Bay field. The trust was originally funded with $15 million and, with accumulated interest, increased to $16.7 million at December 31, 2008. We may draw from the trust upon the authorization, and subsequent completion, of qualifying abandonment activities at our East Bay field. At June 30, 2010, we had $11.1 million remaining in restricted escrow funds for decommissioning work in our East Bay field, $5.1 million of which will be available for draw upon authorization, and subsequent completion, of additional qualifying decommissioning activities as that work progresses. The remaining $6.0 million will remain restricted until substantially all required decommissioning in the East Bay field is complete. Through June 30, 2010, we had made draws of $5.6 million. During July 2010, we made an additional draw of $1.1 million. Amounts on deposit in the trust account are reflected in Restricted cash in the accompanying condensed consolidated balance sheets.

We record liabilities when we deliver production that is in excess of our interest in certain properties. In addition to these imbalances, we may, from time to time, be allocated cash sales proceeds in excess of amounts that we estimate are due to us for our interest in production. These allocations may be subject to further review, may require more information to resolve or may be in dispute. In July 2010, we were notified by a purchaser of oil production from one of our non-operated fields that we were allocated, and received sales proceeds from, more oil production than we actually sold to that purchaser. These third party misallocations may date back to 2006. The oil purchaser’s initial estimate of the oil volumes misallocated to us was approximately 74,000 barrels, which may be valued at up to $6.9 million based on information provided by the oil purchaser. We have previously recorded an amount that we believe may be payable related to a potential reallocation, which amount is reflected in accrued expenses in the accompanying condensed consolidated balance sheet as of June 30, 2010.

We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments, increases or decreases, to our net costs or revenues and the related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account.

In the ordinary course of business, we are a defendant in various other legal proceedings. We do not expect our exposure in these other proceedings, individually or in the aggregate, to have a material adverse effect on our financial position, results of operations or liquidity.

Item 2.

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

Statements we make in this Quarterly Report on Form 10-Q (the “Quarterly Report”) which express a belief, expectation or intention, as well as those that are not historical fact, may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Our forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the headings “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors” in Items 1 and 1A of Part 1 of our 2009 Annual Report.

OVERVIEW

The Company was incorporated as a Delaware corporation in January 1998 and operates 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 state and federal waters offshore Louisiana.

We maintain a website at www.eplweb.com that contains information about us, including links to our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all related amendments as soon as reasonably practicable after providing such reports to the SEC.

We use the successful efforts method of accounting for oil and natural gas producing activities. 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 activities result in no reserves in commercial quantities. Seismic, geological and geophysical, and delay rental expenditures are expensed as they are incurred. We conduct various 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 2009 Annual Report includes a discussion of our critical accounting policies, which have not changed significantly since the end of the last fiscal year.

We produce both oil and natural gas. Throughout this Quarterly Report, when we refer to “total production,” “total reserves,” “percentage of production,” “percentage of reserves,” or any similar term, we have converted our natural gas reserves or production into barrel equivalents. For this purpose, six thousand cubic feet of natural gas is equal to one barrel of oil, which is based on the relative energy content of natural gas and oil. Natural gas liquids are aggregated with oil in this Quarterly Report.

Outlook

Our reorganization under Chapter 11 in 2009 restructured our balance sheet and substantially reduced our indebtedness, providing for an improved capital structure and enhanced financial flexibility. Since the reorganization, we have continued to improve our financial strength, repaying all of our high yield PIK Notes and entering into the Amended Credit Facility, which provides us with a borrowing base of $70 million and availability under the revolving credit portion of $45 million as of June 30, 2010.

We entered 2010 with a continuing focus on 1) achieving meaningful cost reductions in general and administrative (“G&A”) expenses and lease operating expenses (“LOE”); 2) converting non-producing reserves to cash flow; and 3) developing a core competency in plugging, abandonment and decommissioning operations. We allocate capital in a rigorous and disciplined manner intended to achieve an overall lower risk capital expenditure profile that focuses on maximizing rate of return and requires projects to compete on that basis.

While we expect that our 2010 average oil production levels will exceed our 2009 levels, we expect our overall production in barrels of oil equivalent to decline in 2010 as a result of natural gas production declines that occurred in the second half of 2009 that have continued through the first half of 2010 and are expected to continue for the remainder of 2010. Prior to 2010, we established an initial low-risk capital budget oriented towards stabilizing production at the levels experienced in the quarter ended December 31, 2009 and have since continued to develop additional production enhancing opportunities to be considered in 2010 and 2011, some of which have been approved in excess of our initial capital budget. As of the date of this filing, our authorized exploration and development capital budget is $64 million, as compared with an initial capital budget at the first of the year of $45 million. At this capital budget level, we estimate that our overall production in barrels of oil equivalent will decline during the remainder of 2010 and in 2011. Our key areas of operations and our plans for future exploration and development activities do not include any deepwater areas. Additionally, we have meaningful acreage and exploitation, development and exploration opportunities in the state waters offshore Louisiana. As a result, our plans have not been materially impacted by the recently announced regulatory actions taken with respect to leases in federal waters. However, the recent Deepwater Horizon incident has affected our ability to secure certain equipment necessary to conduct simultaneous drilling operations in our East Bay field.

We continue to focus on growth opportunities within our existing development portfolio and strategic opportunities to take advantage of our improved capital structure and enhanced financial flexibility. These opportunities, for which we do not budget, include acquiring assets. We continue to evaluate our existing portfolio of undeveloped leases for exploration opportunities, and we will consider purchasing interests in undeveloped leaseholds and participating in third party drilling opportunities to complement our existing asset base. In light of the recent regulatory actions taken with respect to leases in federal waters, it is unclear when the federal government will offer additional offshore acreage for lease.

We continue to focus on our core competency in plugging, abandonment and decommissioning operations in an attempt to maximize efficiencies and reduce our overall costs in that area of operations. We expect these efforts will enable us to achieve our objectives of prudently removing idle infrastructure throughout the remaining productive lives of our fields and, over time, reducing ongoing LOE associated with maintaining idle infrastructure.

We continue to generate prospects, strive to maintain an extensive inventory of drillable prospects in-house and maintain exposure to new opportunities through relationships with industry partners. Generally, we attempt to fund any exploration and development expenditures with internally generated cash flows.

Our drilling program has been more active in 2010 compared to 2009, though our initial capital budget was scheduled predominantly for the first half of 2010. Our longer term operating strategy is to increase our oil and natural gas reserves and production while focusing on reducing exploration and development costs and operating costs to be competitive with our offshore Gulf of Mexico industry peers.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as oil and natural gas prices, tropical weather, economic, political and regulatory developments and availability of 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 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. See “Risk Factors” in Item 1A of our 2009 Annual Report and Item 1A of Part II of this Quarterly Report for a more detailed discussion of these risks.

Results of Operations

Our Chapter 11 reorganization did not result in the disposition of any of our oil and natural gas properties. As a result, the comparability of certain components of our operating results and key operating performance measures, specifically those related to production, average oil and natural gas selling prices, revenues and LOE, was not significantly impacted by the reorganization. For accounting purposes, the Predecessor Company’s operations are deemed to have ceased on September 30, 2009, and a new entity is deemed to have begun operations as of that date. As a result, the condensed consolidated financial statements of the Predecessor Company are not comparable to those of the Successor Company. For those items that are not comparable, we have included additional analysis to supplement the discussion. The following line items in our condensed consolidated statements of operations for the three and six months ended June 30, 2010 are not comparable to the three and six months ended June 30, 2009 due to our reorganization and application of fresh-start accounting:

•

Depreciation, depletion and amortization;

•

Accretion of liability for asset retirement obligations;

•

Income (loss) from operations;

•

Interest expense;

•

Income (loss) before reorganization items and income taxes;

•

Income (loss) before income taxes; and

•

Net income (loss).

Three Months Ended June 30, 2010

During the three months ended June 30, 2010, we completed eight (8) recompletion operations, seven (7) of which were successful; three (3) exploratory drilling operations, all of which were successful; and one (1) development well which was successful.

Our operating results for the three months ended June 30, 2010, compared to the three months ended June 30, 2009, reflect higher average selling prices for both our oil and natural gas and declines in LOE and G&A expenses. Additionally, our product mix reflects an increase in oil production and a decline in natural gas production. Our average daily production of both oil and natural gas has declined in the three months ended June 30, 2010 as compared to the three months ended March 31, 2010. We expect that this trend will continue during 2010 and into the first half of 2011.

For the three months ended June 30, 2010, our revenues increased 26% as compared to the three months ended June 30, 2009 due primarily to higher average selling prices for our oil production and the increase in oil production. Our overall production volumes declined by 14%, on a barrel equivalent basis, for the three months ended June 30, 2010 when compared to the three months ended June 30, 2009.

Our Gulf of Mexico shelf production decreased in the three months ended June 30, 2010, as compared to the three months ended June 30, 2009, due primarily to natural reservoir declines in the second half of 2009 and continuing into the first half of 2010. Our deepwater production, primarily natural gas, declined for the quarter ended June 30, 2010, as compared to the quarter ended June 30, 2009, due primarily to natural reservoir decline from our deepwater well. We expect that our deepwater production will continue to decline in the future.

In addition to the items addressed above, our net loss for the three months ended June 30, 2010, as compared to the net loss for the three months ended June 30, 2009, reflects an increase in impairments and a $5.6 million loss on extinguishment of debt resulting from redemption of the PIK Notes. Our net loss for the three months ended June 30, 2009 also includes $11.7 million in costs associated with the reorganization.

Our effective tax rate for the three months ended June 30, 2010 was 36%. Our effective tax rate for the three months ended June 30, 2009 was zero because we provided a valuation allowance against the net deferred tax assets generated during the three months ended June 30, 2009.

Six Months Ended June 30, 2010

During the six months ended June 30, 2010, we completed thirteen (13) recompletion operations, eleven (11) of which were successful; five (5) exploratory drilling operations, four (4) of which were successful; and one (1) development well which was successful.

Our operating results for the six months ended June 30, 2010, compared to the six months ended June 30, 2009, reflect higher average selling prices for both our oil and natural gas and declines in LOE and G&A expenses. Additionally, our product mix reflects an increase in oil production and a decrease in natural gas production for the six months ended June 30, 2010 as compared to the six months ended June 30, 2009.

For the six months ended June 30, 2010, our revenues increased 45% as compared to the six months ended June 30, 2009 due primarily to significantly higher average selling prices for our oil production and the increase in oil production. Our overall production volumes declined by 5%, on a barrel equivalent basis, for the six months ended June 30, 2010 when compared to the six months ended June 30, 2009.

Our Gulf of Mexico shelf production decreased in the six months ended June 30, 2010, as compared to the six months ended June 30, 2009, due primarily to natural reservoir declines in the second half of 2009 and continuing into the first half of 2010. Our deepwater production, primarily natural gas, declined for the six months ended June 30, 2010, as compared to the six months ended June 30, 2009, which was due primarily to natural reservoir decline from our deepwater well. We expect that our deepwater production will continue to decline in the future.

In addition to the items addressed above, our net income for the six months ended June 30, 2010, as compared to the net loss for the six months ended June 30, 2009, reflects an increase in impairments, significant reductions in interest expense due primarily to our reorganization and a $5.6 million loss on extinguishment of debt resulting from redemption of the PIK Notes. Our net loss for the six months ended June 30, 2009 also includes $12.6 million in costs associated with the reorganization.

Our effective tax rate for the six months ended June 30, 2010 was 36%. Our effective tax rate for the six months ended June 30, 2009 was zero because we provided a valuation allowance against the net deferred tax assets generated during the six months ended June 30, 2009.

RESULTS OF OPERATIONS

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


	Successor Company			Predecessor Company			Successor Company			Predecessor Company
	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net production (per day):
Oil (Bbls)		6,411			5,167			6,817			5,195
Natural gas (Mcf)		43,549			64,679			47,220			62,047
Total barrels of oil equivalent		13,669			15,947			14,687			15,536
Average sales prices, excluding impact of derivatives:
Oil (per Bbl)	$	70.54		$	51.31		$	71.01		$	44.07
Natural gas (per Mcf)		4.29			3.69			4.82			4.19
Total (per Boe)		46.76			31.60			48.47			31.48
Oil and natural gas revenues (in thousands):
Oil	$	41,149		$	24,124		$	87,616		$	41,440
Natural gas		17,014			21,737			41,230			47,071

Total		58,163			45,861			128,846			88,511
Impact of derivatives instruments settled during the period (1):
Oil (per Bbl)	$	(4.66	)	$	5.11		$	(5.17	)	$	2.71
Natural gas (per Mcf)	$	0.02		$	(0.57	)	$	0.01		$	0.02
Average costs (per Boe):
LOE	$	10.99		$	10.37		$	10.58		$	11.03
Depreciation, depletion and amortization (DD&A)		20.99			23.47			21.05			23.54
Accretion of liability for asset retirement obligations		2.59			1.27			2.42			1.31
Taxes, other than on earnings		1.83			0.95			1.62			0.99
G&A expenses		3.92			5.23			3.41			6.00
Increase (decrease) in oil and natural gas revenues between periods presented due to:
Changes in prices of oil	$	9,041					$	25,330
Changes in production volumes of oil		7,984						20,846

Total increase in oil sales		17,025						46,176
Changes in prices of natural gas	$	3,536					$	7,052
Changes in production volumes of natural gas		(8,259	)					(12,893	)

Total decrease in natural gas sales		(4,723	)					(5,841	)

(1)	See Other Income and Expense section for further discussion of the impact of derivative instruments.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Revenue and Net Loss


	Successor Company Three Months Ended June 30,2010			Predecessor Company Three Months Ended June 30, 2009
				(in thousands)			$ Change		% Change
Oil and natural gas revenues	$	58,163		$	45,861		$	12,302		27	%
Net loss		(4,610	)		(33,661	)		NM		NM

NM – Not Meaningful

Our oil and natural gas revenues increased primarily due to a 37% increase in average selling prices for our oil and a 24% increase in oil production in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, offset by a 33% decline in natural gas production in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009. The percentage of production represented by oil has increased for us. Oil represented 47% of total production for the three months ended June 30, 2010, as compared to 32% of total production for the three months ended June 30, 2009.

Operating Expenses

Our operating expenses primarily consist of the following:


	Successor Company Three Months Ended June 30, 2010		Predecessor Company Three Months Ended June 30, 2009
			(in thousands)		$ Change			% Change
LOE	$	13,675	$	15,044	$	(1,369	)		(9	)%
Exploration expenditures and dry hole costs		783		746		37			5	%
Impairments		10,885		1,467		9,418			NM
DD&A, including accretion expense		29,328		35,897		NM			NM
G&A expenses		4,875		7,584		(2,709	)		(36	)%
Taxes, other than on earnings		2,276		1,376		900			65	%

NM – Not Meaningful

Impairment expense for the three months ended June 30, 2010 was primarily related to two producing fields which were determined to have future net cash flows less than their carrying values due primarily to reservoir performance resulting in the write down of these properties to their estimated fair values as of June 30, 2010.

G&A expenses, which include cash and non-cash stock based compensation of $0.6 million and $1.0 million in the three months ended June 30, 2010 and 2009, respectively, decreased in the three months ended June 30, 2010, as compared to the three months ended June 30, 2009, primarily as a result of the impact of cost reduction efforts on the 2010 quarter.

Taxes, other than on earnings, increased in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, due primarily to higher average sales prices for oil (which is taxed based on value) and higher estimated property tax assessments in 2010.

Other Income and Expense

Our interest expense was impacted by our reorganization and is not comparable for the periods presented. Interest expense in the three months ended June 30, 2010 consists primarily of interest expense on our PIK Notes and our Credit Facility. We redeemed all of our outstanding PIK Notes on June 28, 2010. Interest expense in the three months ended June 30, 2009 consists primarily of interest expense on the Predecessor Company Notes. However, we had discontinued accruing interest on the Predecessor Company Notes as of May 1, 2009, the date we filed for reorganization under Chapter 11. As a result of the Chapter 11 reorganization, each holder of the Predecessor Company Notes received such holder’s pro rata portion of approximately 95% of the common stock in the Successor Company, and the Predecessor Company Notes were converted into common stock and discharged in the reorganization.

Other income (expense) in the three months ended June 30, 2010 includes a net gain of $7.0 million consisting of an unrealized gain of $9.6 million due to the change in fair market value of derivative instruments and a loss of $2.6 million on derivative instruments settled during the quarter primarily from the impact of our oil fixed-price swaps. Other income (expense) in the three months ended June 30, 2009 includes a net loss of $0.9 million on derivative instruments settled during the quarter. As a result of the liquidity challenges that led to our filing for reorganization under Chapter 11, we had settled all remaining outstanding derivative contracts during the three months ended June 30, 2009.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Revenue and Net Income (Loss)


	Successor Company Six Months Ended June 30,2010		Predecessor Company Six Months Ended June 30, 2009
			(in thousands)			$ Change		% Change
Oil and natural gas revenues	$	128,846	$	88,511		$	40,335		46	%
Net income (loss)		506		(65,532	)		NM		NM

NM – Not Meaningful

Our oil and natural gas revenues increased primarily due to a 61% increase in average selling prices for our oil and a 31% increase in oil production in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, offset in part by a 24% decline in natural gas production in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. The percentage of production represented by oil has increased for us. Oil represented 46% of total production for the six months ended June 30, 2010, as compared to 33% of total production for the six months ended June 30, 2009.

Operating Expenses

Our operating expenses primarily consist of the following:


	Successor Company Six Months Ended June 30, 2010		Predecessor Company Six Months Ended June 30, 2009
			(in thousands)		$ Change			% Change
LOE	$	28,117	$	31,021	$	(2,904	)		(9	)%
Exploration expenditures and dry hole costs		2,637		1,318		1,319			NM
Impairments		11,654		6,580		5,074			77	%
DD&A, including accretion expense		62,405		69,871		NM			NM
G&A expenses		9,063		16,873		(7,810	)		(46	)%
Taxes, other than on earnings		4,313		2,775		1,538			55	%

NM – Not Meaningful

We drilled one (1) exploratory dry hole in the six months ended June 30, 2010, resulting in $1.8 million of dry hole costs. In addition, the expense in the six months ended June 30, 2010 includes $0.8 million of seismic expenditures and delay rentals. The expense in the six months ended June 30, 2009 is comprised of $1.3 million of seismic expenditures and delay rentals.

Impairment expense for the six months ended June 30, 2010 was primarily related to two producing fields which were determined to have future net cash flows less than their carrying values due primarily to reservoir performance resulting in the write down of these properties to their estimated fair values as of June 30, 2010. Impairment expense for the six months ended June 30, 2009 was primarily related to two producing fields which were determined to have future net cash flows less than their carrying values due primarily to commodity price declines and reservoir performance resulting in the write down of these properties to their estimated fair values.

G&A expenses, which include cash and non-cash stock based compensation of $0.7 million and $2.5 million in the six months ended June 30, 2010 and 2009, respectively, decreased in the six months ended June 30, 2010, as compared to the six months ended June 30, 2009, primarily as a result of legal and financial advisory fees associated with our balance sheet restructuring efforts in the 2009 period and the impact of cost reduction efforts on the 2010 period.

Taxes, other than on earnings, increased in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, due primarily to higher average sales prices for oil (which is taxed based on value) and higher estimated property tax assessments in 2010.

Other Income and Expense

Our interest expense was impacted by our Chapter 11 reorganization and is not comparable for the periods presented. Interest expense in the six months ended June 30, 2010 consists primarily of interest expense on our PIK Notes and our Credit Facility. We redeemed all of our outstanding PIK Notes on June 28, 2010. Interest expense in the six months ended June 30, 2009 consists primarily of interest expense on the Predecessor Company Notes. However, as described above, we had discontinued accruing interest on the Predecessor Company Notes as of May 1, 2009, the date we filed for reorganization under Chapter 11, and the Predecessor Company Notes were discharged in the reorganization.

Other income (expense) in the six months ended June 30, 2010 includes a net gain of $5.0 million consisting of an unrealized gain of $11.3 million due to the change in fair market value of derivative instruments and a loss of $6.3 million on derivative instruments settled during the period primarily from the impact of our oil fixed-price swaps. Other income (expense) in the six months ended June 30, 2009 includes a net gain of $2.7 million on derivative instruments settled during the period primarily from the impact of a decline in oil and natural gas selling prices during 2009. As a result of the liquidity challenges that led to our filing for reorganization under Chapter 11, we had settled all of our outstanding derivative contracts during the six months ended June 30, 2009.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

A key focus of management in 2010 was to reduce our cost of capital. In June 2010, we reached an agreement (described below) to amend our $125 million Senior Secured Credit Facility with General Electric Capital Corporation, which enabled us to redeem our PIK Notes. On June 28, 2010, we paid a total of $70.9 million of principal and accrued interest in connection with the redemption of the PIK Notes. We redeemed all of the PIK Notes at 100% of the outstanding aggregate principal amount, plus accrued and unpaid interest. As a result, we recorded a loss on extinguishment of debt totaling $5.6 million which represents the total of the unamortized original issue discount and unamortized deferred financing costs associated with the PIK Notes. We used cash on hand and a portion of the proceeds of the new term loan under the Amended Credit Facility to fund the redemption.

On June 16, 2010, we entered into an amendment (the “First Amendment”) to our Credit Facility dated as of September 21, 2009, (the “Credit Facility”) (together with the First Amendment, the “Amended Credit Facility”) with General Electric Capital Corporation, as administrative agent (the “Agent”), and the lender parties thereto (the “Lenders”). Upon its effectiveness on June 28, 2010, the Amended Credit Facility established a $70 million borrowing base consisting of (a) a new $25 million term loan payable, with interest, in six equal monthly installments of principal from July 28, 2010 to December 28, 2010 and (b) a revolving credit facility with a three-year term that may be used for revolving credit loans and letters of credit up to an initial maximum principal amount of $45 million. The interest rate spread on loans and letters of credit under the Amended Credit Facility are based on the level of utilization and will range from 3.75% to 4.25% for base rate borrowings and 4.75% to 5.25% for LIBOR borrowings. The First Amendment contains the Lenders’ consent for us to redeem all outstanding principal and pay all accrued interest on our PIK Notes, which redemption occurred on June 28, 2010 and was a condition to the effectiveness of the First Amendment.

As of June 30, 2010, we had Cash and cash equivalents of $28.2 million and no borrowings outstanding under the revolver component of the Amended Credit Facility. The undrawn commitment under the Amended Credit Facility was $45 million as of that date. We had total indebtedness of $25 million consisting of the term loan component of the Amended Credit Facility. As of July 31, 2010, the Cash and cash equivalents on our balance sheet has increased and we have reduced the amount outstanding under the Amended Credit Facility by the July 2010 term loan principal payment of $4.2 million.

We entered 2010 with a capital budget of approximately $57 million, of which approximately $45 million was allocated for exploration and development expenditures and $12 million for plugging, abandonment and other decommissioning expenditures. As of the date of this filing, our authorized exploration and development capital budget is $64 million. At this capital budget level, we estimate that our overall production in barrels of oil equivalent will decline during the remainder of 2010 and in 2011. Further, we expect that our oil and natural gas reserves will decline as of December 31, 2010 as compared to December 31, 2009. Our key areas of operations and our plans for future exploration and development activities do not include any deepwater areas. Additionally, we have meaningful acreage and exploitation, development and exploration opportunities in the state waters of offshore Louisiana. As a result, our plans have not been materially impacted by the recently announced regulatory actions taken with respect to leases in federal waters. However, the recent Deepwater Horizon incident has affected our ability to secure certain equipment necessary to conduct simultaneous drilling operations in our East Bay field.

Capital expenditures on our deepwater portfolio do not currently fit with our near-term strategy and may not fit with our longer term strategy, given the significant capital requirements and long lead times from initial investment to first production associated with deepwater oil and natural gas exploration and development activities. We are currently evaluating our deepwater portfolio and may monetize or trade assets in that portfolio. As a result of the recent increased level of uncertainty surrounding the regulatory environment and availability of equipment and resources to support deepwater development plans, we believe our ability to realize value from our deepwater lease positions in the near term is diminished.

We expect our 2010 cash flows from operations to increase as compared to our operating cash flows for the year ended December 31, 2009, primarily as a result of higher anticipated sales prices for oil and natural gas. We expect our cash used in investing activities for 2010 will increase as compared with our investing cash flows for the year ended December 31, 2009, as a result of our planned increase in capital expenditures in 2010.

We have experienced and may experience in the future substantial working capital deficits. Our working capital deficits have historically resulted from increased accounts payable and accrued expenses related to ongoing exploration and development costs, which may be capitalized as noncurrent assets. At June 30, 2010, our working capital deficit was $24.8 million, compared to $16.9 million at December 31, 2009. However, as previously noted, we have $45 million undrawn and available under the revolver component of our Amended Credit Facility.

We maintain restricted escrow funds in a trust for future plugging, abandonment and other decommissioning costs at our East Bay field. The trust was originally funded with $15 million and, with accumulated interest, had increased to $16.7 million at December 31, 2008. We have made draws to date through July 2010 of $6.7 million, with $3.3 million drawn in 2010. We may draw from the trust upon the authorization, and subsequent completion, of qualifying abandonment activities at our East Bay field. As of July 30, 2010, we had $10.0 million remaining in restricted escrow funds for decommissioning work in our East Bay field, $4.0 million of which will be available for draw upon authorization, and subsequent completion, of additional qualifying decommissioning activities as that work progresses. The remaining $6.0 million will remain restricted until substantially all required decommissioning in the East Bay field is complete. Amounts on deposit in the trust account are reflected in Restricted cash on our condensed consolidated balance sheets.

Shortly following our emergence from Chapter 11 reorganization, we provided the Minerals Management Service, now known as the Bureau of Ocean Energy Management, Regulation and Enforcement (the “Bureau”) with surety bonds in support of decommissioning obligations on certain federal leases in the Gulf of Mexico, and we resumed production from the federal portion of the East Bay field. During April 2010, we regained supplemental waiver status, and we are no longer required to post these surety bonds. Restricted cash totaling $8.9 million held as collateral for these surety bonds and other surety bonding obligations was released to us during the second quarter of 2010. We expect the cancellation of these surety bonds will reduce our surety bonding costs.

The Bureau and other regulatory bodies, including those regulating the decommissioning of our pipelines and facilities under the jurisdiction of the state of Louisiana, may change their requirements or enforce requirements in a manner inconsistent with our expectations, which could materially increase the cost of such activities and/or accelerate the timing of cash expenditures and could have a material adverse effect on our financial position, results of operations and cash flows. For important additional information regarding risks related to our regulatory environment, see the Risk Factors in Part II, Item 1A of this Quarterly Report and in Part I, Item 1A of our 2009 Annual Report.

Analysis of Cash Flows – Six Months Ended June 30, 2010

The following table sets forth our cash flows (in thousands):


	Successor Company Six Months Ended June 30, 2010			Predecessor Company Six Months Ended June 30, 2009
Cash flows provided by operating activities	$	67,488		$	9,160
Cash flows used in investing activities		(16,557	)		(27,574	)
Cash flows provided by (used in) financing activities		(49,488	)		40,000

The increase in our 2010 cash flows from operations primarily reflects the impact of the increase in oil and natural gas sales prices realized during the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. Operating cash flows for the six months ended June 30, 2010 also include cash payments totaling $15.8 million related to the redemption of our PIK Notes on June 28, 2010, which amount includes $9.7 million of interest for the period from September 21, 2009 through the redemption date and $6.1 million of original issue discount.

Net cash used in investing activities declined in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009 primarily due to a decrease in restricted cash. Our investing cash flows for the six months ended June 30, 2009, reflect, in part, that a higher level of capital expenditure activities occurred in the fourth quarter of 2008 compared to the fourth quarter of 2009, which resulted in cash payments for prior quarter work during the quarter ended March 31, 2009 that were higher than those in the quarter ended March 31, 2010.

Net cash used in financing activities during the six months ended June 30, 2010 reflects the redemption of the PIK Notes and payments on the term loan component of our Credit Facility, partially offset by proceeds from the term loan component of our Amended Credit Facility. Net cash provided by financing activities during the six months ended June 30, 2009 reflects increased utilization of the Predecessor Company’s credit facility to fund working capital shortfalls caused by the decline in production and the precipitous decline in oil and natural gas sales prices in 2009.

We have not paid any cash dividends in the past on our common stock. The covenants in certain debt instruments to which we are a party, including the Amended Credit Facility, place certain restrictions and conditions on our ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and other factors determined by our board of directors.

Cautionary Statement Concerning Forward Looking Statements

This Quarterly Report contains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When used herein, the words “will,” “would,” “should,” “likely,” “estimates,” “thinks,” “strives,” “may,” “anticipates,” “expects,” “believes,” “intends,” “goals,” “plans,” or “projects” and similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. While our management considers the expectations and assumptions to be reasonable when and as made, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•

our ability to retain and motivate key executives and other necessary personnel;

•

changes in general economic conditions;

•

uncertainties in reserve and production estimates;

•

unanticipated recovery or production problems;

•

hurricane and other weather-related interference with business operations;

•

risks and hazards inherent in the production of oil and natural gas;

•

the effects of delays in completion of, or shut-ins of, gas gathering systems, pipelines and processing facilities;

•

oil and natural gas prices and competition;

•

the impact of derivative positions;

•

production expense estimates;

•

cash flow estimates;

•

future financial performance;

•

planned and unplanned capital expenditures;

•

volatility in the financial and credit markets or in oil and natural gas prices;

•

the impact of political and regulatory developments; and

•

other matters that are discussed in our filings with the SEC.

These statements are based on current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Investors are cautioned that all such statements involve risks and uncertainties. Our actual decisions, performance and results may differ materially. Important trends or factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in the section “Risk Factors” in Part 1, Item 1A and elsewhere in our 2009 Annual Report, elsewhere in this Quarterly Report, and in our reports and registration statements filed from time to time with the SEC, and other announcements we make from time to time.

Although we believe that the assumptions on which any forward-looking statements are based in this Quarterly Report and other periodic reports filed by us are reasonable when and as made, no assurance can be given that such assumptions will prove correct. All forward-looking statements in this Quarterly Report are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Quarterly Report and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by applicable securities laws and regulations.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view our ongoing market-risk exposure.

Interest Rate Risk

We are exposed to changes in interest rates which affect the interest earned on our interest-bearing deposits and the interest paid on borrowings under our Amended Credit Facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. At June 30, 2010, we had total indebtedness outstanding of $25.0 million, which bears interest at floating rates and consists of borrowings outstanding under the Amended Credit Facility. At June 30, 2010, the weighted average interest rate under the Amended Credit Facility was approximately 7.5%. If market interest rates were to average 1% higher in the third quarter of 2010, interest expense for the period on floating-rate debt would be expected to increase by approximately $51,000.

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 Amended Credit Facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may 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.

Historically, we have used commodity derivative instruments to manage commodity price risks associated with future oil and natural gas production. As of June 30, 2010, the following derivative instruments were outstanding:

Oil Contracts


	Fixed-Price Swaps									Puts
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Swap Price ($/Bbl)		Fair Value			Daily Average Volume (Bbls)		Volume (Bbls)		Floor Price ($/Bbl)		Fair Value
July 2010		2,700		83,700	$	68.84	$	(582,128	)		503		15,600	$	60.00	$	156
August 2010—November 2010		625		76,200	$	69.65	$	(547,115	)		1,673		204,150	$	60.00	$	179,840
December 2010		1,200		37,200	$	70.37	$	(274,768	)		1,302		40,350	$	60.00	$	70,935
January 2011—July 2011		2,261		479,250	$	71.13	$	(3,645,470	)		502		106,500	$	60.00	$	313,430
August 2011—November 2011		502		61,200	$	72.18	$	(456,405	)		1,301		158,700	$	60.00	$	660,967
December 2011		948		29,400	$	72.64	$	(210,953	)		1,302		40,350	$	60.00	$	173,317

All of our commodity derivative instruments are with one counterparty. For information regarding this counterparty and collateral requirements related to our derivative instruments, see Note 4, “Indebtedness” in the condensed consolidated financial statements in Part 1, Item 1 of this Quarterly Report.

Item 4.

CONTROLS AND PROCEDURES.

(a) Quarterly Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. This information is also accumulated and communicated to management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, under the supervision and with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the most recent fiscal quarter reported on herein. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2010.

Because of their inherent limitations, disclosure controls and procedures may not prevent or detect misstatements. Furthermore, projections of any evaluation of effectiveness to future periods are subject to the risk that such controls and procedures may become inadequate because of changes in conditions or deterioration in the degree of compliance with the controls or procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.

(b) Changes in Internal Control Over Financial Reporting

There were no changes in our system of internal control over financial reporting during the three months ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS.

For information regarding legal proceedings, see the information in Note 7, “Commitments and Contingencies” in the condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report.

Item 1A.

RISK FACTORS.

In addition to the other information set forth in this Form 10-Q, you should carefully consider the factors discussed in Part I, “Item 1A. – Risk Factors” in our 2009 Annual Report that could materially affect our business, financial condition or future results. The risks described in this Quarterly Report and in our 2009 Annual Report are not the only risks facing the Company. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may materially adversely affect our business, financial condition and future results.

The following risk factor is added to the risk factors included in our 2009 Annual Report:

The recent explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico and the resulting oil spill may significantly impact our risks.

The recent explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico and the resulting oil spill may significantly impact the risks we face, including but not limited to: potential increases in regulations in areas including health and safety, environmental, permitting, taxation and equipment specifications; increased difficulty in obtaining permits to drill offshore wells; higher royalty rates; higher insurance costs or the unavailability of insurance on commercially acceptable terms; higher financial responsibility requirements or financial responsibility requirements that are beyond our capacity; decreased access to equipment, personnel and infrastructure; and less favorable investor perception of the risk related to investing in the oil and natural gas exploration and production industry. Any of these factors could have a material adverse effect on our business, financial position or results of operations and cash flows, and our ability to execute our business plans.

The following risk factor from our 2009 Annual Report is revised:

Even though we have successfully entered into the Credit Facility, as amended, and emerged from our Chapter 11 reorganization, we will continue to have substantial capital needs that we may not be able to satisfy in the future.

Like other oil and natural gas exploration and production companies, our business has substantial capital requirements. In order to provide us with access to capital immediately following our emergence from our Chapter 11 reorganization, we entered into the Credit Facility, which we amended in June 2010, and issued the PIK Notes, which we redeemed in June 2010, and we intend to finance our capital expenditures primarily through cash flow from operations. Because our cash flows are subject to a range of economic, competitive and business risks, we may not be able to generate sufficient cash flow from operations to meet our debt payment obligations and to fund these capital requirements. Additionally, the amounts available to us under the Amended Credit Facility may not be sufficient for our capital requirements not funded by initial cash flows, and we may not be able to access additional financing resources for a variety of reasons, including restrictive covenants in the Amended Credit Facility and the general lack of available capital due to the condition of the global credit markets. If we are unable to make scheduled payments on the Amended Credit Facility, or if our financing requirements are not met by the Amended Credit Facility and we are unable to access sources of additional financing on terms we find acceptable, our business, operations, financial condition and cash flows will be negatively impacted.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None

Item 3.

DEFAULTS UPON SENIOR SECURITIES.

None

Item 5.

OTHER INFORMATION.

None

Item 6.

EXHIBITS.

The exhibits marked with the cross symbol (†) are management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K. We have not filed with this Quarterly Report copies of the instruments defining rights of all holders of the long-term debt of us and our consolidated subsidiaries based upon the exception set forth in Item 601(b)(4)(iii)(A) of Regulation S-K. Copies of such instruments will be furnished to the SEC upon request.

Exhibit

Incorporated by
Reference

SEC File

Filed/

Furnished

Number

Exhibit Description

Form

Number

Exhibit

Filing Date

Herewith

2.0

Second Amended Joint Plan of Reorganization of Energy Partners, Ltd. and certain of its Subsidiaries Under Chapter 11 of the Bankruptcy Code, as Modified as of September 16, 2009

10-Q

001-16179

2.0

5/6/2010

3.1

Amended and Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of September 21, 2009

8-K/A

001-16179

3.1

9/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-K/A

001-16179

3.2

9/21/2009

4.1

Notice of Redemption by Energy Partners, Ltd., as Issuer, and the Guarantors named therein, to The Bank of New York Mellon Trust Company, N.A., as Trustee, dated June 16, 2010

8-K

001-16179

99.1

6/17/2010

10.1†

Offer Letter to Jonathan S. Gross, accepted on May 25, 2010

8-K

001-16179

10.1

6/4/2010

10.2†

Fifth Amendment to the Energy Partners, Ltd. Change of Control Severance Plan

10.3†

First Amendment to Employment Agreement, dated as of April 12, 2010 between Energy Partners, Ltd. and Gary Hanna

31.1

Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1

Section 1350 Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2

Section 1350 Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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.

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.

INDEX TO EXHIBITS

Exhibit

Incorporated by
Reference

SEC File

Filed/

Furnished

Number

Exhibit Description

Form

Number

Exhibit

Filing Date

Herewith

2.0

Second Amended Joint Plan of Reorganization of Energy Partners, Ltd. and certain of its Subsidiaries Under Chapter 11 of the Bankruptcy Code, as Modified as of September 16, 2009

10-Q

001-16179

2.0

5/6/2010

3.1

Amended and Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of September 21, 2009

8-K/A

001-16179

3.1

9/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-K/A

001-16179

3.2

9/21/2009

4.1

Notice of Redemption by Energy Partners, Ltd., as Issuer, and the Guarantors named therein, to The Bank of New York Mellon Trust Company, N.A., as Trustee, dated June 16, 2010

8-K

001-16179

99.1

6/17/2010

10.1†

Offer Letter to Jonathan S. Gross, accepted on May 25, 2010

8-K

001-16179

10.1

6/4/2010

10.2†

Fifth Amendment to the Energy Partners, Ltd. Change of Control Severance Plan

10.3†

First Amendment to Employment Agreement, dated as of April 12, 2010 between Energy Partners, Ltd. and Gary Hanna

31.1

Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1

Section 1350 Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2

Section 1350 Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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