Edgar Filing: ENERGY PARTNERS LTD

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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 November 1, 2010, there were 40,091,237 shares of the Registrant’s Common Stock, par value $0.001 per share, outstanding.

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		Page

PART I - FINANCIAL INFORMATION			3

Item 1.	Financial Statements:		3

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

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

	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended September 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		20

Item 4.	Controls and Procedures		21

PART II - OTHER INFORMATION			21

Item 1.	Legal Proceedings		21

Item 1A.	Risk Factors		21

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		22

Item 3.	Defaults Upon Senior Securities		22

Item 5.	Other Information		22

Item 6.	Exhibits		23

PART I - FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


(In thousands, except share data)	September 30, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	30,227		$	26,745
Trade accounts receivable - net		23,371			27,958
Receivables from insurance		2,088			5,464
Fair value of commodity derivative instruments		314			914
Deferred tax assets		5,128			5,768
Prepaid expenses		4,473			2,940

Total current assets		65,601			69,789
Property and equipment - successful efforts method of accounting for oil and natural gas properties		689,681			648,517
Less accumulated depreciation, depletion and amortization		(142,656	)		(37,535	)

Net property and equipment		547,025			610,982
Restricted cash		9,981			22,147
Other assets		2,399			3,647
Deferred financing costs - net of accumulated amortization of $1,265 and $325 at September 30, 2010 and December 31, 2009, respectively		2,479			2,663

	$	627,485		$	709,228


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	17,288		$	14,047
Accrued expenses		33,543			32,822
Asset retirement obligations		9,168			10,830
Current portion of long-term debt		12,500			18,750
Fair value of commodity derivative instruments		7,192			10,256

Total current liabilities		79,691			86,705
Long-term debt		—			58,590
Asset retirement obligations		60,407			59,150
Deferred tax liabilities		12,620			16,953
Fair value of commodity derivative instruments		768			7,519
Other		20			224

		153,506			229,141

Commitments and contingencies (Note 7)

Stockholders’ equity:
Preferred stock, $0.001 par value per share. Authorized 1,000,000 shares; no shares issued and outstanding at September 30, 2010 and December 31, 2009		—			—
Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued and outstanding 40,091,237 and 40,021,770 at September 30, 2010 and December 31, 2009, respectively		40			40
Additional paid-in capital		502,291			501,059
Accumulated deficit		(28,352	)		(21,012	)

Total stockholders’ equity		473,979			480,087

	$	627,485		$	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 September 30, 2010			Nine Months Ended September 30, 2010			Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Revenue:
Oil and natural gas	$	56,237		$	185,083		$	46,072		$	134,583
Other		34			104			37			302

		56,271			185,187			46,109			134,885
Costs and expenses:
Lease operating		12,857			40,974			15,275			46,296
Transportation		251			1,053			270			699
Exploration expenditures and dry hole costs		1,291			3,928			332			1,650
Impairments		12,366			24,020			1,502			8,082
Depreciation, depletion and amortization		25,323			81,284			29,750			95,944
Accretion of liability for asset retirement obligations		3,200			9,644			1,859			5,536
General and administrative		4,807			13,870			2,620			19,493
Taxes, other than on earnings		3,106			7,419			3,212			5,987
Loss on abandonment activities		276			853			3,159			3,732
Other		(20	)		(106	)		(15	)		(26	)

Total costs and expenses		63,457			182,939			57,964			187,393
Business interruption recovery		—			—			—			1,185

Income (loss) from operations		(7,186	)		2,248			(11,855	)		(51,323	)
Other income (expense):
Interest income		8			105			—			47
Interest expense (contractual interest of $11,335 and $34,076 for the three and nine months ended September 30, 2009, respectively)		(726	)		(8,873	)		(1,576	)		(17,813	)
Gain (loss) on derivative instruments		(3,918	)		1,115			—			2,728
Loss on extinguishment of debt		—			(5,627	)		—			—

		(4,636	)		(13,280	)		(1,576	)		(15,038	)
Loss before reorganization items, loss on discharge of debt, fresh start adjustments and income taxes		(11,822	)		(11,032	)		(13,431	)		(66,361	)
Reorganization items		—			—			(11,596	)		(24,198	)
Loss on discharge of debt		—			—			(2,666	)		(2,666	)
Fresh start adjustments		—			—			57,111			57,111

Income (loss) before income taxes		(11,822	)		(11,032	)		29,418			(36,114	)
Income taxes		3,976			3,692			—			—

Net income (loss)		(7,846	)		(7,340	)		29,418			(36,114	)

Basic earnings (loss) per share	$	(0.20	)	$	(0.18	)	$	0.91		$	(1.12	)
Diluted earnings (loss) per share	$	(0.20	)	$	(0.18	)	$	0.91		$	(1.12	)
Weighted average common shares used in computing earnings (loss) per share:
Basic		40,078			40,059			32,287			32,200
Effect of dilutive stock options and restricted shares		—			—			—			—

Diluted		40,078			40,059			32,287			32,200

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


(In thousands)	Successor Company Nine Months Ended September 30, 2010			Predecessor Company Nine Months Ended September 30, 2009
Cash flows from operating activities:
Net loss	$	(7,340	)	$	(36,114	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		81,284			95,944
Accretion of liability for asset retirement obligations		9,644			5,536
Loss on discharge of debt		—			2,666
Fresh start adjustments		—			(57,111	)
Unrealized gain on derivative contracts		(8,298	)		—
Non cash compensation expense		995			3,689
Deferred income taxes		(3,692	)		—
Repayment of PIK Notes issued for payment of in-kind interest		(3,395	)		—
Exploration expenditures		2,813			126
Impairments		24,020			8,082
Amortization of deferred financing costs and discount on debt		748			8,356
Loss on abandonment activities		853			3,732
Other		—			3
Changes in operating assets and liabilities:
Trade accounts receivable		4,587			4,807
Other receivables		3,376			194
Prepaid expenses		(1,533	)		677
Other assets		342			(641	)
Accounts payable and accrued expenses		3,661			(2,414	)
Other liabilities		(11,073	)		(23,166	)

Net cash provided by operating activities		96,992			14,366

Cash flows provided by (used in) investing activities:
Decrease in restricted cash		12,166			—
Property acquisitions		(623	)		(31	)
Exploration and development expenditures		(43,032	)		(29,723	)
Other property and equipment additions		—			(147	)
Proceeds from sale of oil and gas assets		—			150

Net cash used in investing activities		(31,489	)		(29,751	)

Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		20,394			113,128
Repayments of indebtedness, excluding repayment of PIK Notes issued to pay interest of $3,395		(82,382	)		(55,001	)
Deferred financing costs		(33	)		(798	)

Net cash provided by (used in) financing activities		(62,021	)		57,329

Net increase in cash and cash equivalents		3,482			41,944
Cash and cash equivalents at beginning of period		26,745			1,991

Cash and cash equivalents at end of period	$	30,227		$	43,935

SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING INFORMATION:
Discharge of Senior Unsecured Notes, including accrued interest of $18,663	$	—		$	473,164
Issuance of equity in Successor Company		—			500,874
Debt incurred to repay secured bank credit facility, including accrued interest of $1,085		—			29,084
Debt incurred to pay deferred financing costs and surety bond premium		737			2,790

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.

The financial information as of September 30, 2010 and for the three- and nine-month periods ended September 30, 2010 and the three-month period ended September 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, results of operations and cash flows 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 “SEC”), although management believes that the disclosures made are adequate to make the information not misleading. 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 Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on March 11, 2010 (the “2009 Annual Report”). The results of operations and cash flows for the first nine months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

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 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 nine-month periods ended September 30, 2009 and the statement of cash flows for the nine-month period ended September 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 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 or loss 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:


	Nine Months Ended September 30, 2010
	(in thousands)
Balance at December 31, 2009	$	69,980
Accretion expense		9,644
Revisions		860
Liabilities settled		(10,909	)

Balance at September 30, 2010		69,575
Less: Amount to be settled within the next twelve months		(9,168	)

Balance at September 30, 2010, noncurrent asset retirement obligations	$	60,407

(4) INDEBTEDNESS

Total indebtedness was as follows:


(In thousands)	September 30, 2010		December 31, 2009
Term loan component of Amended Credit Facility, interest rate of 7.25% on September 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	$	12,500	$	—
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		12,500		77,340
Current portion of indebtedness		12,500		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 is 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, and, absent a novation, would have given the Derivative Counterparty the right to liquidate the derivative contracts or require additional financial support. However, we resolved this potential with the Derivative Counterparty on October 29, 2010, when we entered into a second amendment to our Credit Facility and an intercreditor agreement which allow for a new counterparty to our derivative contracts. On October 29, 2010, we also entered into a novation agreement under which, effective October 1, 2010, we novated certain of our derivative contracts. The novation agreement effectively transfers all the rights, liabilities, duties and obligations of the Derivative Counterparty under those contracts to the new counterparty.

At September 30, 2010, our borrowing base was $57.5 million under the Amended Credit Facility including the $12.5 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. See Note 6 for information regarding fair values of our derivative instruments.

As of September 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 ($/Bbl)		Daily Average Volume (Bbls)		Volume (Bbls)		Floor Price ($/Bbl)
October 2010—November 2010		600		36,600	$	70.00		1,800		109,800	$	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

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


	Successor Company						Predecessor Company
	Three Months Ended September 30, 2010			Nine Months Ended September 30, 2010			Three Months Ended September 30, 2009		Nine Months Ended September 30, 2009
	(in thousands)
Derivative contracts:
Unrealized gain (loss) due to change in fair market value	$	(3,018	)	$	8,298		$	—	$	—
Realized gain (loss) on settlement		(900	)		(7,183	)		—		2,728

Total gain (loss) on derivative instruments	$	(3,918	)	$	1,115		$	—	$	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 September 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 September 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	$	624		$	624		$	—	$	624		$	—
Derivative instruments	$	(7,960	)	$	(7,960	)	$	—	$	(7,960	)	$	—

The fair value of our variable rate debt under our Amended Credit Facility approximated the carrying amount at September 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 are amortizing the premium paid to expense over the term of the agreement. At September 30, 2010, we estimate that the fair value of this financial instrument approximates the carrying amount of approximately $0.4 million.

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 nine months ended September 30, 2010 was primarily related to the decline in our estimate of future natural gas prices as of September 30, 2010 as compared to June 30, 2010 affecting two producing fields, including our deepwater producing well, and to reservoir performance of one of these fields and one additional producing field. These producing fields were determined to have future net cash flows less than their carrying values resulting in the write down of these properties to their estimated fair values during the nine months ended September 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 September 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. Through September 30, 2010, we had made draws of $6.7 million. During October 2010, we made additional draws totaling $0.4 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 September 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. Such adjustments may be material. 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.

(8) SUBSEQUENT EVENTS

We recorded approximately $1.0 million of dry hole costs in the three months ended September 30, 2010 related to one exploratory dry hole which we completed drilling in October 2010. We expect costs in the fourth quarter of 2010 to total approximately $1.5 million related to this dry hole.

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. Our website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Quarterly Report or any other filing that we make with 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 provided us with an initial borrowing base of $70 million and availability under the revolving credit portion of $45 million. As of September 30, 2010, our borrowing base is $57.5 million, reflecting the remaining principal balance on the term loan of $12.5 million and continued availability under the revolving credit portion of $45 million.

During 2010 we have had 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.

Our development efforts during 2010 have been focused on our oil-rich East Bay field where average daily production has increased 47% for the quarter ended September 30, 2010 as compared to the quarter ended September 30, 2009 and 16% for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. As a result, we expect that our 2010 average oil production levels will exceed our 2009 levels. 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 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 primarily as a result of natural gas production declines that began in the second half of 2009 and are expected to continue. 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.

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, our cash flows, 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. The following line items in our condensed consolidated statements of operations for the three and nine months ended September 30, 2010 are not comparable to the three and nine months ended September 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;

•

Loss before reorganization items, loss on discharge of debt, fresh start adjustments and income taxes;

•

Income (loss) before income taxes; and

•

Net income (loss).

Three Months Ended September 30, 2010

During the three months ended September 30, 2010, we completed four (4) recompletion operations, two (2) of which were successful; and two (2) exploratory drilling operations, both of which were successful.

Our operating results for the three months ended September 30, 2010, compared to the three months ended September 30, 2009, reflect higher average selling prices for both our oil and natural gas, an increase in our oil production and a decline in LOE expenses, primarily due to operational efficiencies resulting from our continued focus on cost reduction efforts in the 2010 period.

For the three months ended September 30, 2010, our revenues increased 22% as compared to the three months ended September 30, 2009 due primarily to the increase in oil production and higher average selling prices for our oil production. Our overall production volumes declined by 12%, on a barrel equivalent basis, for the three months ended September 30, 2010 when compared to the three months ended September 30, 2009. 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 September 30, 2010 as compared to the three months ended June 30, 2010. We expect that this trend will continue during 2010 and in 2011.

Our producing fields are primarily located on the Gulf of Mexico shelf and in the deepwater Gulf of Mexico. Our Gulf of Mexico shelf production decreased in the three months ended September 30, 2010, as compared to the three months ended September 30, 2009, due primarily to natural reservoir declines in the second half of 2009 and continuing into the first nine months of 2010, offset in part by an overall increase in production from our core oil producing fields. Our deepwater production, primarily natural gas, decreased 25% for the quarter ended September 30, 2010, as compared to the quarter ended September 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 loss before reorganization items, loss on discharge of debt, fresh start adjustments and income taxes for the three months ended September 30, 2010, as compared to the three months ended September 30, 2009, reflects an increase in impairments related primarily to natural gas price declines during the quarter.

Our effective income tax rate for the three months ended September 30, 2010 was 33.6%. The income tax benefit recorded on the net loss for the three months ended September 30, 2010 was reduced due to our applying the change in our estimated effective income tax rate for the full 2010 year, from 36% to 37.4%, to our net deferred tax liabilities. The change in our estimated effective income tax rate for 2010 is related to state income taxes. Our effective income tax rate for the three months ended September 30, 2009 was zero because we provided a valuation allowance against the net deferred tax assets generated during the three months ended September 30, 2009.

Nine Months Ended September 30, 2010

During the nine months ended September 30, 2010, we completed seventeen (17) recompletion operations, thirteen (13) of which were successful; seven (7) exploratory drilling operations, six (6) of which were successful; and one (1) development well which was successful.

Our operating results for the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009, reflect higher average selling prices for both our oil and natural gas and declines in LOE and G&A expenses. The decline in LOE and G&A expenses is primarily due to the impact of our cost reduction efforts in the 2010 period.

For the nine months ended September 30, 2010, our revenues increased 37% as compared to the nine months ended September 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 8%, on a barrel equivalent basis, for the nine months ended September 30, 2010 when compared to the nine months ended September 30, 2009. Additionally, our product mix reflects an increase in oil production and a decrease in natural gas production for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009.

Our Gulf of Mexico shelf production decreased in the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, due primarily to natural reservoir declines in the second half of 2009 and continuing into the first nine months of 2010, offset in part by an overall increase in production from our core oil producing fields. Our deepwater production, primarily natural gas, decreased 20% for the nine months ended September 30, 2010, as compared to the nine months ended September 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 loss before reorganization items, loss on discharge of debt, fresh start adjustments and income taxes for the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, reflects an increase in impairments, significant reductions in interest expense due primarily to our reorganization and a loss on extinguishment of debt resulting from redemption of the PIK Notes.

Our effective income tax rate for the nine months ended September 30, 2010 was 33.5%. The income tax benefit recorded on the net loss for the nine months ended September 30, 2010 was reduced due to our applying the change in our estimated effective income tax rate for the full 2010 year, from 36% to 37.4%, to our net deferred tax liabilities. The change in our estimated effective income tax rate for 2010 is related to state income taxes. Our effective income tax rate for the nine months ended September 30, 2009 was zero because we provided a valuation allowance against the net deferred tax assets generated during the nine months ended September 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 September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
Net production (per day):
Oil (Bbls)		6,219			4,992		6,615			5,127
Natural gas (Mcf)		41,102			59,025		45,158			61,029
Total barrels of oil equivalent		13,069			14,830		14,142			15,299
Average sales prices, excluding impact of derivatives:
Oil (per Bbl)	$	69.72		$	61.77	$	70.60		$	49.88
Natural gas (per Mcf)		4.32			3.26		4.67			3.89
Total (per Boe)		46.77			33.77		47.94			32.22
Oil and natural gas revenues (in thousands):
Oil	$	39,891		$	28,372	$	127,507		$	69,812
Natural gas		16,346			17,700		57,576			64,771

Total		56,237			46,072		185,083			134,583
Impact of derivatives instruments settled during the period (1):
Oil (per Bbl)	$	(1.57	)	$	—	$	(4.03	)	$	1.82
Natural gas (per Mcf)	$	—		$	—	$	0.01		$	0.01
Average costs (per Boe):
LOE	$	10.69		$	11.20	$	10.61		$	11.09
Depreciation, depletion and amortization (DD&A)		21.06			21.81		21.05			22.97
Accretion of liability for asset retirement obligations		2.66			1.36		2.50			1.33
Taxes, other than on earnings		2.58			2.35		1.92			1.43
G&A expenses		4.00			1.92		3.59			4.67
Increase (decrease) in oil and natural gas revenues between periods presented due to:
Changes in prices of oil	$	3,650				$	29,008
Changes in production volumes of oil		7,869					28,687

Total increase in oil sales		11,519					57,695
Changes in prices of natural gas	$	5,701				$	12,917
Changes in production volumes of natural gas		(7,055	)				(20,112	)

Total decrease in natural gas sales		(1,354	)				(7,195	)

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

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

Revenue and Net Income (Loss)


	Successor Company Three Months Ended September 30, 2010			Predecessor Company Three Months Ended September 30, 2009
				(in thousands)			$ Change		% Change
Oil and natural gas revenues	$	56,237		$	46,072		$	10,165		22	%
Loss before reorganization items, loss on discharge of debt, fresh start adjustments and income taxes		(11,822	)		(13,431	)		NM		NM
Net income (loss)		(7,846	)		29,418			NM		NM

NM – Not Meaningful

Our oil and natural gas revenues increased primarily due to a 13% increase in average selling prices for our oil and a 25% increase in oil production in the three months ended September 30, 2010 as compared to the three months ended September 30, 2009, offset by a 30% decline in natural gas production in the three months ended September 30, 2010 as compared to the three months ended September 30, 2009. The percentage of production represented by oil has increased for us. Oil represented 48% of total production for the three months ended September 30, 2010, as compared to 34% of total production for the three months ended September 30, 2009.

Operating Expenses

Our operating expenses primarily consist of the following:


	Successor Company Three Months Ended September 30, 2010		Predecessor Company Three Months Ended September 30, 2009
			(in thousands)		$ Change			% Change
LOE	$	12,857	$	15,275	$	(2,418	)		(16	)%
Exploration expenditures and dry hole costs		1,291		332		959			NM
Impairments		12,366		1,502		10,864			NM
DD&A, including accretion expense		28,523		31,609		NM			NM
G&A expenses		4,807		2,620		2,187			83	%
Taxes, other than on earnings		3,106		3,212		(106	)		(3	)%

NM – Not Meaningful

Impairment expense for the three months ended September 30, 2010 was primarily related to the decline in our estimate of future natural gas prices as of September 30, 2010 as compared to June 30, 2010 affecting two producing fields, including our deepwater producing well. The related producing fields were determined to have future net cash flows less than their carrying values resulting in the write down of these properties to their estimated fair values as of September 30, 2010.

G&A expenses, which include cash and non-cash stock based compensation of $0.3 million and $1.4 million in the three months ended September 30, 2010 and 2009, respectively, increased in the three months ended September 30, 2010, as compared to the three months ended September 30, 2009, primarily as a result of litigation costs and costs incurred in our acquisition efforts in the three months ended September 30, 2010.

Taxes, other than on earnings, decreased in the three months ended September 30, 2010 as compared to the three months ended September 30, 2009, due primarily to higher local property tax assessments in the 2009 period, partially offset by higher production taxes in the 2010 period due to higher average sales prices for oil (which is taxed based on value) and from higher estimated franchise taxes in the 2010 period.

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 three months ended September 30, 2010 consists primarily of interest expense on the term loan component of our Amended Credit Facility. Interest expense in the three months ended September 30, 2009 consists primarily of interest expense on the Predecessor Company’s secured bank credit facility, since 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 September 30, 2010 includes a net loss of $3.9 million consisting of an unrealized loss of $3.0 million due to the change in fair market value of derivative instruments and a loss of $0.9 million on derivative instruments settled during the quarter primarily from the impact of our oil fixed-price swaps. We had no gain or loss on derivative instruments in the three months ended September 30, 2009. 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.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Revenue and Net Loss


	Successor Company Nine Months Ended September 30, 2010			Predecessor Company Nine Months Ended September 30, 2009
				(in thousands)			$ Change		% Change
Oil and natural gas revenues	$	185,083		$	134,583		$	50,500		38	%
Loss before reorganization items, loss on discharge of debt, fresh start adjustments and income taxes		(11,032	)		(66,361	)		NM		NM
Net loss		(7,340	)		(36,114	)		NM		NM

NM – Not Meaningful

Our oil and natural gas revenues increased primarily due to a 42% increase in average selling prices for our oil and a 29% increase in oil production in the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009, offset in part by a 26% decline in natural gas production in the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. The percentage of production represented by oil has increased for us. Oil represented 47% of total production for the nine months ended September 30, 2010, as compared to 34% of total production for the nine months ended September 30, 2009.

Operating Expenses

Our operating expenses primarily consist of the following:


	Successor Company Nine Months Ended September 30, 2010		Predecessor Company Nine Months Ended September 30, 2009
			(in thousands)		$ Change			% Change
LOE	$	40,974	$	46,296	$	(5,322	)		(11	)%
Exploration expenditures and dry hole costs		3,928		1,650		2,278			NM
Impairments		24,020		8,082		15,938			NM
DD&A, including accretion expense		90,928		101,480		NM			NM
G&A expenses		13,870		19,493		(5,623	)		(29	)%
Taxes, other than on earnings		7,419		5,987		1,432			24	%

NM – Not Meaningful

We completed drilling of one exploratory dry hole in the nine months ended September 30, 2010 and we recorded approximately $1.0 million of dry hole costs in the three months ended September 30, 2010 related to one exploratory dry hole which we completed drilling in October 2010. We expect costs in the fourth quarter of 2010 to total approximately $1.5 million related to this dry hole. In addition, the expense in the nine months ended September 30, 2010 includes $1.1 million of seismic expenditures and delay rentals.

Impairment expense for the nine months ended September 30, 2010 was primarily related to the decline in our estimate of future natural gas prices as of September 30, 2010 as compared to June 30, 2010 affecting two producing fields, including our deepwater producing well, and to reservoir performance of one of these fields and one additional producing field. These producing fields were determined to have future net cash flows less than their carrying values resulting in the write down of these properties to their estimated fair values during the nine months ended September 30, 2010. Impairment expense for the nine months ended September 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 $1.0 million and $3.9 million in the nine months ended September 30, 2010 and 2009, respectively, decreased in the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, primarily as a result of the impact of cost reduction efforts on the 2010 period, offset in part by litigation costs and costs incurred in our acquisition efforts in the 2010 period.

Taxes, other than on earnings, increased in the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009, due primarily to production taxes resulting from higher average sales prices for oil (which is taxed based on value) and higher estimated franchise taxes in the 2010 period.

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 nine months ended September 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 nine months ended September 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 nine months ended September 30, 2010 includes a net gain of $1.1 million consisting of an unrealized gain of $8.3 million due to the change in fair market value of derivative instruments and a loss of $7.2 million on derivative instruments settled during the period primarily from the impact of our oil fixed-price swaps. Other income (expense) in the nine months ended September 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, during the quarter ended June 30, 2010, 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 is 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.

The borrowing base of $57.5 million under the Amended Credit Facility at September 30, 2010 includes the $12.5 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.

As of September 30, 2010, we had Cash and cash equivalents of $30.2 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 $12.5 million consisting of the term loan component of the Amended Credit Facility.

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 primarily as a result of natural gas production declines that began in the second half of 2009 and are expected to continue. 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.

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 September 30, 2010, our working capital deficit was $14.1 million, compared to $16.9 million at December 31, 2009. However, 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 October 2010 of $7.1 million, with $3.7 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 October 31, 2010, we had $9.6 million remaining in restricted escrow funds for decommissioning work in our East Bay field, $3.6 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 – Nine Months Ended September 30, 2010

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


	Successor Company Nine Months Ended September 30, 2010			Predecessor Company Nine Months Ended September 30, 2009
Cash flows provided by operating activities	$	96,992		$	14,366
Cash flows used in investing activities		(31,489	)		(29,751	)
Cash flows provided by (used in) financing activities		(62,021	)		57,329

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 nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. Operating cash flows for the nine months ended September 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 in the nine months ended September 30, 2010 reflects an increase in exploration and development expenditures as compared to the nine months ended September 30, 2009, substantially offset by a decrease in restricted cash. Our investing cash flows for the nine months ended September 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 nine months ended September 30, 2010 reflects the redemption of the PIK Notes and payments on the term loan component of our Credit Facility and our Amended Credit Facility, partially offset by proceeds from the term loan component of our Amended Credit Facility. Net cash provided by financing activities during the nine months ended September 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 September 30, 2010, we had total indebtedness outstanding of $12.5 million, which bears interest at floating rates and consists of borrowings outstanding under the Amended Credit Facility. At September 30, 2010, the weighted average interest rate under the Amended Credit Facility was 7.25%. 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 $20,000.

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 September 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 ($/Bbl)		Fair Value (In thousands)			Daily Average Volume (Bbls)		Volume (Bbls)		Floor Price ($/Bbl)		Fair Value (In thousands)
October 2010—November 2010		600		36,600	$	70.00	$	(391	)		1,800		109,800	$	60.00	$	4
December 2010		1,200		37,200	$	70.37	$	(430	)		1,302		40,350	$	60.00	$	9
January 2011—July 2011		2,261		479,250	$	71.13	$	(5,980	)		502		106,500	$	60.00	$	126
August 2011—November 2011		502		61,200	$	72.18	$	(784	)		1,301		158,700	$	60.00	$	375
December 2011		948		29,400	$	72.64	$	(375	)		1,302		40,350	$	60.00	$	110

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 September 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 September 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
Number

Exhibit Description

Incorporated by
Reference

Form

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
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-A12B/A

001-16179

3.1

9/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-A12B/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-Q

001-16179

10.2

8/5/2010

10.3†

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

10-Q

001-16179

10.3

8/5/2010

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.

INDEX TO EXHIBITS

Exhibit
Number

Exhibit Description

Incorporated by
Reference

Form

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
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-A12B/A

001-16179

3.1

9/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-A12B/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-Q

001-16179

10.2

8/5/2010

10.3†

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

10-Q

001-16179

10.3

8/5/2010

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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