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 June 30, 2011

¨	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 x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or smaller reporting company. See definitions of “large accelerated 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 1, 2011, there were 40,236,729 shares of the Registrant’s Common Stock, par value $0.001 per share, outstanding.

TABLE OF CONTENTS


		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:		1

Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2011 and December 31, 2010			1

Condensed Consolidated Statements of Operations (Unaudited) for the three and six months ended June 30, 2011 and 2010			2

Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended June 30, 2011 and 2010			3

Notes to Condensed Consolidated Financial Statements (Unaudited)			4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3.	Quantitative and Qualitative Disclosures about Market Risk		27

Item 4.	Controls and Procedures		28

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings		28

Item 1A.	Risk Factors		29

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		30

Item 3.	Defaults Upon Senior Securities		30

Item 5.	Other Information		30

Item 6.	Exhibits		31

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, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	76,228		$	33,553
Trade accounts receivable—net		30,357			21,443
Receivables from insurance		805			2,088
Fair value of commodity derivative instruments		127			186
Deferred tax assets		183			2,693
Prepaid expenses		8,622			3,303

Total current assets		116,322			63,266
Property and equipment, under the successful efforts method of accounting for oil and natural gas properties		967,419			719,147
Less accumulated depreciation, depletion and amortization		(228,308	)		(168,055	)

Net property and equipment		739,111			551,092
Restricted cash		6,022			8,489
Other assets		1,877			1,814
Deferred financing costs—net of accumulated amortization of $437 and $1,656 at June 30, 2011 and December 31, 2010, respectively		5,620			2,245

	$	868,952		$	626,906

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	12,774		$	18,358
Accrued expenses		43,892			28,394
Asset retirement obligations		12,034			16,902
Fair value of commodity derivative instruments		5,604			12,320

Total current liabilities		74,304			75,974
Long-term debt		204,046			—
Asset retirement obligations		74,991			54,681
Deferred tax liabilities		26,293			22,469
Fair value of commodity derivative instruments		3,644			—
Other		663			666
Commitments and contingencies (Note 8)

		383,941			153,790
Stockholders’ equity:
Preferred stock, $0.001 par value per share. Authorized 1,000,000 shares; no shares issued and outstanding at June 30, 2011 and December 31, 2010		—			—
Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued 40,243,074 and 40,091,664 at June 30, 2011 and December 31, 2010, respectively; shares outstanding 40,236,729 and 40,091,664 at June 30, 2011 and December 31, 2010, respectively		40			40
Additional paid-in capital		503,965			502,556
Accumulated deficit		(18,986	)		(29,480	)
Treasury stock, at cost, 6,345 shares at June 30, 2011		(8	)		—

Total stockholders’ equity		485,011			473,116

	$	868,952		$	626,906

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands, except per share data)	2011			2010			2011			2010
Revenue:
Oil and natural gas	$	92,798		$	58,163		$	160,013		$	128,846
Other		32			34			66			70

		92,830			58,197			160,079			128,916
Costs and expenses:
Lease operating		17,908			13,675			33,239			28,117
Transportation		236			312			371			802
Exploration expenditures and dry hole costs		822			783			1,370			2,637
Impairments		2,886			10,885			13,674			11,654
Depreciation, depletion and amortization		25,522			26,106			46,585			55,961
Accretion of liability for asset retirement obligations		3,804			3,222			7,379			6,444
General and administrative		4,796			4,875			10,083			9,063
Taxes, other than on earnings		3,695			2,276			7,013			4,313
Other		1,902			740			2,032			491

Total costs and expenses		61,571			62,874			121,746			119,482

Income (loss) from operations		31,259			(4,677	)		38,333			9,434
Other income (expense):
Interest income		17			88			27			97
Interest expense		(4,974	)		(3,945	)		(7,444	)		(8,147	)
Gain (loss) on derivative instruments		13,831			6,957			(11,694	)		5,033
Loss on early extinguishment of debt		—			(5,627	)		(2,377	)		(5,627	)

		8,874			(2,527	)		(21,488	)		(8,644	)

Income (loss) before income taxes		40,133			(7,204	)		16,845			790
Deferred income tax benefit (expense)		(15,130	)		2,594			(6,351	)		(284	)

Net income (loss)		25,003			(4,610	)		10,494			506

Basic earnings (loss) per share	$	0.62		$	(0.12	)	$	0.26		$	0.01
Diluted earnings (loss) per share	$	0.62		$	(0.12	)	$	0.26		$	0.01
Weighted average common shares used in computing earnings (loss) per share:
Basic		40,109			40,057			40,095			40,049
Effect of dilutive stock options and restricted shares		128			—			122			31

Diluted		40,237			40,057			40,217			40,080

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


(In thousands)	Six Months Ended June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	10,494		$	506
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		46,585			55,961
Accretion of liability for asset retirement obligations		7,379			6,444
Unrealized gain on derivative contracts		(3,063	)		(11,316	)
Non-cash compensation		1,276			739
Deferred income taxes		6,334			284
Repayment of PIK Notes issued for payment of in-kind interest		—			(3,395	)
Exploration expenditures		131			1,827
Impairments		13,674			11,654
Amortization of deferred financing costs and discount on debt		689			457
Loss on early extinguishment of debt		2,377			—
Other		1,731			577
Changes in operating assets and liabilities:
Trade accounts receivable		(9,523	)		4,249
Other receivables		1,283			1,701
Prepaid expenses		(4,814	)		(830	)
Other assets		(13	)		622
Accounts payable and accrued expenses		5,011			3,003
Other liabilities		(17,362	)		(4,995	)

Net cash provided by operating activities		62,189			67,488

Cash flows provided by (used in) investing activities:
Decrease in restricted cash		2,467			11,007
Property acquisitions		(196,350	)		(615	)
Exploration and development expenditures		(22,994	)		(26,910	)
Other property and equipment additions		(361	)		(39	)

Net cash used in investing activities		(217,238	)		(16,557	)

Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		203,794			20,394
Repayments of indebtedness		—			(69,882	)
Deferred financing costs		(6,189	)		—
Exercise of stock options		119			—

Net cash provided by (used in) financing activities		197,724			(49,488	)

Net increase in cash and cash equivalents		42,675			1,443
Cash and cash equivalents at beginning of period		33,553			26,745

Cash and cash equivalents at end of period	$	76,228		$	28,188

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 are an independent oil and natural gas exploration and production company. Our current operations are concentrated in the U.S. Gulf of Mexico shelf focusing on state and federal waters offshore Louisiana.

The financial information as of June 30, 2011 and for the three-and six-month periods ended June 30, 2011 and June 30, 2010 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 “SEC”). The condensed consolidated balance sheet at December 31, 2010 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, 2010, as amended (the “2010 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.

(2) ACQUISITIONS

On February 14, 2011, we acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests surrounding the Mississippi River delta and a related gathering system (the “ASOP Properties”) from Anglo-Suisse Offshore Partners, LLC (“ASOP”) for $200.7 million in cash, subject to purchase price adjustments to reflect an economic effective date of January 1, 2011 (the “ASOP Acquisition”). As of December 31, 2010, the ASOP Properties had estimated proved reserves of approximately 8.1 Mmboe, of which 84% were oil and 76% were proved developed reserves. The primary factors considered by management in acquiring the ASOP Properties include the belief that the ASOP Acquisition provides an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus on oil-weighted assets in our core area of expertise in the Gulf of Mexico shelf.

The ASOP Acquisition was financed with the proceeds from the sale of $210 million in aggregate principal amount of 8.25% senior notes due 2018 (the “8.25% Notes”), which were offered in a private placement only to qualified institutional buyers under Rule 144A promulgated under the Securities Act of 1933, as amended (the “Securities Act”), or to persons outside of the United States in compliance with Regulation S promulgated under the Securities Act. After deducting the initial purchasers’ discount and offering expenses, we realized net proceeds of approximately $202 million. On July 14, 2011, we and our guarantor subsidiaries (the “Guarantors”) filed a registration statement with the SEC, which was declared effective on July 26, 2011, offering to exchange a new series of freely tradable notes having substantially identical terms as the 8.25% Notes (“exchange notes”) for the 8.25% Notes. See Note 5, “Indebtedness” for more information regarding our 8.25% Notes.

We have accounted for the ASOP Acquisition using the purchase method of accounting for business combinations, and therefore we have estimated the fair value of the ASOP Properties as of the February 14, 2011 acquisition date. In the estimation of fair value, management uses various valuation methods including (i) comparable company analysis, which estimates the value of the ASOP Properties based on the implied valuations of other similar operations; (ii) comparable asset transaction analysis, which estimates the value of the acquired operations based upon publicly announced transactions of assets with similar characteristics; (iii) comparable merger transaction analysis, which, much like comparable asset transaction analysis, estimates the value of operations based upon publicly announced transactions with similar characteristics, except that merger analysis analyzes public to public merger transactions rather than solely asset transactions; and (iv) discounted cash flow analysis, which estimates the value of the ASOP Properties by determining the present value of estimated future cash flows. The fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 7, “Fair Value Measurements.”

The following allocation of the purchase price as of February 14, 2011 is preliminary and includes significant estimates. This preliminary allocation is based on information that was available to management at the time these consolidated financial statements were prepared and is subject to revision as management finalizes key assumptions in the fair value models, primarily finalization of the oil and natural gas reserve analysis. Accordingly, the allocation may change as additional information becomes available and is assessed by management, and the impact of such changes may be material.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects management’s current estimate of adjustments to purchase price provided for by the purchase and sale agreement of approximately $4.4 million to reflect an economic effective date of January 1, 2011.


(In thousands)	February 14, 2011
Oil and natural gas properties	$	219,889
Asset retirement obligations		(23,548	)

Net assets acquired	$	196,341

Revenues attributable to the ASOP Properties for the three and six months ended June 30, 2011 were $35.5 million and $52.0 million, respectively. Lease operating expenses attributable to the ASOP Properties for the three and six months ended June 30, 2011 were $4.5 million and $6.2 million, respectively. We have determined that the presentation of net income attributable to the ASOP Properties is impracticable due to the integration of the related operations upon acquisition. We incurred approximately $0.5 million in fees related to the acquisition, which were included in general and administrative expenses in the accompanying consolidated statement of operations for the six months ended June 30, 2011.

The following supplemental pro forma information presents consolidated results of operations as if the ASOP Acquisition had occurred on January 1, 2010. This supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations and b) the statements of revenues and direct operating expenses for the ASOP Properties, which were derived from ASOP’s historical accounting records. This information does not purport to be indicative of results of operations that would have occurred had the acquisition occurred on January 1, 2010, nor is such information indicative of any expected future results of operations.


	Pro Forma Three Months Ended June 30,					Pro Forma Six Months Ended June 30,
	2011		2010			2011		2010
	(in thousands, except per share data)
Revenue	$	92,830	$	81,559		$	172,837	$	172,632
Net income (loss)	$	25,003	$	(622	)	$	12,398	$	8,365
Basic earnings (loss) per share	$	0.62	$	(0.02	)	$	0.31	$	0.21
Diluted earnings (loss) per share	$	0.62	$	(0.02	)	$	0.31	$	0.21

(3) 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.

(4) ASSET RETIREMENT OBLIGATIONS

Changes in our asset retirement obligations were as follows:


	Six Months Ended June 30, 2011
	(in thousands)
Balance at December 31, 2010	$	71,583
ASOP Acquisition liabilities assumed		23,548
Accretion expense		7,379
Liabilities incurred		144
Revisions		1,731
Liabilities settled		(17,360	)

Balance at June 30, 2011		87,025
Less: End of period, current portion		(12,034	)

End of period, noncurrent portion	$	74,991

(5) INDEBTEDNESS

In connection with the ASOP Acquisition (see Note 2), on February 14, 2011, we issued $210.0 million in aggregate principal amount of our 8.25% Notes due 2018. Furthermore, our credit facility existing on that date was terminated and replaced with a new credit facility. The termination of our prior credit facility during the six months ended June 30, 2011 resulted in a loss on early extinguishment of debt of $2.4 million, primarily due to writing off the unamortized deferred financing costs associated with the terminated facility.

Senior Notes Offering

On February 14, 2011, we issued the $210.0 million in aggregate principal amount of our 8.25% Notes under an Indenture, dated as of February 14, 2011 (the “Indenture”). As described in Note 2, “Acquisitions,” we used the net proceeds from the offering of the 8.25% Notes of $202.0 million, after deducting the initial purchasers’ discount and offering expenses payable by us, to acquire the ASOP Properties for a purchase price of $200.7 million, before adjustments to reflect an economic effective date of January 1, 2011, and for general corporate purposes. The 8.25% Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest due semi-annually, in arrears, on February 15 and August 15 of each year, commencing on August 15, 2011. The 8.25% Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Notes will mature on February 15, 2018. In connection with the execution of the Indenture, we also entered into a registration rights agreement, dated as of February 14, 2011 (the “Registration Rights Agreement”).

Under the Registration Rights Agreement, we and the Guarantors agreed to (i) file a registration statement for the exchange notes with the SEC within 150 days after the closing of the 8.25% Notes offering, which registration statement was filed on July 14, 2011; (ii) use commercially reasonable efforts to cause the registration statement to be declared effective as soon as practicable, but in any event within 210 days after the closing of the 8.25% Notes offering, which registration statement was declared effective on July 26, 2011; and (iii) use commercially reasonable efforts to close the exchange offer 30 business days after the registration statement is declared effective. In certain circumstances, we may be required to file a shelf registration statement to cover resales of the 8.25% Notes. The use of the shelf registration statement will be subject to certain customary suspension periods. If we and the Guarantors do not meet these deadlines, we will be required to pay special interest to holders of 8.25% Notes under certain circumstances.

On or after February 15, 2015, we may on any one or more occasions redeem all or a part of the 8.25% Notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest and special interest, if any, on the 8.25% Notes redeemed, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 15^th of the years indicated below, subject to the rights of holders of the 8.25% Notes on the relevant record date to receive interest on the relevant interest payment date:


Year	Percentage
2015		104.125	%
2016		102.063	%
2017 and thereafter		100.000	%

Any such redemption and notice may, in our discretion, be subject to the satisfaction of one or more conditions precedent, including but not limited to, the occurrence of a change of control. Unless we default in the payment of the redemption price, interest will cease to accrue on the 8.25% Notes or portions thereof called for redemption on the applicable redemption date.

At any time prior to February 15, 2014, we may, at our option, on any one or more occasions redeem with the net cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of outstanding 8.25% Notes (which amount includes additional notes issued under the Indenture), upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to 108.250% of the principal amount of the notes redeemed, plus accrued and unpaid interest and special interest, if any, to the redemption date, provided that: (1) at least 65% of the aggregate principal amount of the 8.25% Notes issued under the Indenture (which amount includes additional notes issued under the Indenture) remains outstanding immediately after the occurrence of such redemption; and (2) the redemption occurs within 90 days of the date of the closing of such equity offering. This option to redeem up to 35% of the aggregate principal amount of outstanding 8.25% Notes with the net cash proceeds of certain equity offerings is considered an embedded derivative. We estimate that the fair value of this option at June 30, 2011 is not material.

In addition, we may, at our option, on any one or more occasions redeem all or a part of the 8.25% Notes prior to February 15, 2015 at a redemption price equal to 100% of the principal amount of the 8.25% Notes redeemed plus a “make-whole” premium as of, and accrued and unpaid interest and special interest, if any, to the redemption date.

If we experience a change of control (as defined in the Indenture), each holder of the 8.25% Notes will have the right to require us to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of the 8.25% Notes at a price in cash equal to 101% of the aggregate principal amount of the 8.25% Notes repurchased, plus accrued and unpaid interest and special interest, if any, to the date of repurchase. If we engage in certain asset sales, within 360 days of such sale, we generally must use the net cash proceeds from such sales to repay outstanding senior secured debt (other than intercompany debt or any debt owed to an affiliate), to acquire all or substantially all of the assets, properties or capital stock of one or more companies in our industry, to make capital expenditures or to invest in our business. When any such net proceeds that are not so applied or invested exceed $20.0 million, we must make an offer to purchase the 8.25% Notes and other pari passu debt that is subject to similar asset sale provisions in an aggregate principal amount equal to the excess net cash proceeds. The purchase price of each 8.25% Note (or other pari passu debt) so purchased will be 100% of its principal amount, plus accrued and unpaid interest and special interest, if any, to the repurchase date, and will be payable in cash.

The Indenture, among other things, limits our ability to: (i) declare or pay dividends, redeem subordinated debt or make other restricted payments; (ii) incur or guarantee additional debt or issue preferred stock; (iii) create or incur liens; (iv) incur dividend or other payment restrictions affecting restricted subsidiaries; (v) consummate a merger, consolidation or sale of all or substantially all of our assets; (vi) enter into sale-leaseback transactions, (vii) enter into transactions with affiliates; (viii) transfer or sell assets; (ix) engage in business other than our current business and reasonably related extensions thereof; or (x) issue or sell capital stock of certain subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the Indenture.

New Senior Credit Facility

On February 14, 2011, we entered into our new credit facility with BMO Capital Markets, as lead arranger, and Bank of Montreal, as administrative agent and a lender. The terms of our new credit facility establish a revolving credit facility with a four-year term that may be used for revolving credit loans and letters of credit up to an aggregate principal amount of $250.0 million, subject to an initial borrowing base of $150.0 million. The maximum amount of letters of credit that may be outstanding at any one time is $20.0 million, and the amount available under the revolving credit facility is limited by the borrowing base. With the consent of the agent, we also have the ability to increase the aggregate commitments under the new credit facility by up to $100.0 million to the extent that existing and/or future lenders provide additional commitments. Upon the closing of our new credit facility, our then existing credit facility was terminated. We had no amounts drawn under our new credit facility at June 30, 2011.

The interest rate spread on loans and letters of credit under our new credit facility will be based on the level of utilization and will range from a base rate plus a margin of 1.00% to 2.00% for base rate borrowings and LIBOR plus a margin of 2.00% to 3.00% for LIBOR borrowings. A commitment fee of 0.5% is payable on the unused portion of the borrowing base. Interest on our base rate borrowings will be payable quarterly, in arrears, and interest on our LIBOR borrowings will be payable on the last day of each relevant interest period, except that in the case of any interest period that is longer than three months, interest will be payable on each successive date three months after the first day of such interest period.

Our new credit facility contains customary covenants, default provisions and collateral requirements. As described in the agreement underlying our new credit facility, we must maintain, for each period for which a covenant certification is required, (a) a minimum current ratio (as defined in the agreement for our new credit facility) of 1.0 to 1.0, (b) a minimum EBITDAX (as defined in the agreement for our new credit facility) to interest expense coverage ratio of 2.5 to 1.0 and (c) a maximum total debt to EBITDAX ratio of 3.5 to 1.0. We will also be required to maintain a commodities hedging program that is in compliance with the requirements set forth in our new credit facility. The determination of our borrowing base under our new credit facility will be based on our proved reserves, at the sole discretion of the lenders. The initial borrowing base was $150.0 million and scheduled borrowing base redeterminations will be made on a semi-annual basis on May 1^st and November 1^st of each year. We were subject to our first borrowing base semi-annual redetermination in May 2011, and our borrowing base has been reaffirmed at $150 million. Our borrowing base will remain at $150.0 million until redetermined. Our new credit facility also places restrictions on the maximum estimated future production volumes that can be subject to commodity derivative instruments.

Our obligations under our new credit facility, as well as any hedging contracts and treasury management agreements with the lenders or affiliates of lenders, are guaranteed by our material domestic subsidiaries and secured by a pledge of 100% of the stock of each material domestic subsidiary and 66²/₃% of each of their foreign material subsidiaries and a first priority lien on substantially all of our and our material subsidiaries’ assets, including our real property assets and the oil and gas properties to which 85% of the present value of our proved reserves is attributable.

(6) 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 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. Our put contracts limit our exposure to declines in the sales price of oil for a limited amount of our production. Our collars limit our exposure to declines in the sales price of oil while giving us the ability to benefit from increases to a certain level in the sales price of oil for a limited amount of our 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, 2011, 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)
July 2011		5,390		167,100	$	86.08		503		15,600	$	60.00
August 2011—November 2011		2,059		251,200	$	90.42		1,301		158,700	$	60.00
December 2011		3,368		104,400	$	90.25		1,302		40,350	$	60.00
January 2012—July 2012		2,167		461,500	$	95.33		—		—		—
August 2012—November 2012		721		88,000	$	95.74		—		—		—
December 2012		1,161		36,000	$	95.28		—		—		—
January 2013—July 2013		1,703		361,000	$	94.28		—		—		—
August 2013—November 2013		426		52,000	$	94.18		—		—		—
December 2013		806		25,000	$	93.98		—		—		—


	Collars
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Strike Price ($/Bbl)
January 2012—July 2012		500		106,500	$	85.00/118.85
August 2012—November 2012		500		61,000	$	85.00/118.85
December 2012		500		15,500	$	85.00/118.85

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Derivative contracts:
Unrealized gain due to change in fair market value	$	23,297		$	9,580		$	3,063		$	11,316
Realized loss on settlement		(9,466	)		(2,623	)		(14,757	)		(6,283	)

Total gain (loss) on derivative instruments	$	13,831		$	6,957		$	(11,694	)	$	5,033

(7) 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, 2011, 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. At June 30, 2011, the carrying amounts and fair values of our derivative instruments are reported as assets totaling $0.2 million and liabilities totaling $9.2 million. At December 31, 2010, the carrying amounts and fair values of our derivative instruments are reported as assets totaling $0.2 million and liabilities totaling $12.3 million.

On June 9, 2011, we entered into an agreement with an insurance company whereby, 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 a fixed amount of cash proceeds to us. This 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 we are amortizing to expense over the term of the agreement. At June 30, 2011, we estimate that the fair value of this financial instrument approximates the carrying amount of approximately $2.5 million, based on the amount of premium paid, which is a Level 3 input within the fair value hierarchy.

As of June 30, 2011, the carrying amount of our 8.25% Notes is $204.0 million, which reflects the $210.0 million face amount, net of the unamortized amount of initial purchasers’ discount of $6.0 million. We estimate the fair value of the 8.25% Notes at approximately $207.2 million, based on bid and offer prices indicated by brokers, which are Level 3 inputs within the fair value hierarchy. The 8.25% Notes are not traded and therefore quoted prices are not available.

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 lease). An impairment loss is indicated if 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 months ended June 30, 2011 was primarily related to reservoir performance at two of our producing fields. These 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 at June 30, 2011. In addition, for the six months ended June 30, 2011, impairment expense was primarily related to reservoir performance at one of our producing fields where a production zone depleted prematurely. In the same field we experienced mechanical difficulties attempting to access a behind-pipe zone and currently do not expect that the behind-pipe reserves will be economically recoverable. This field was determined to have future net cash flows less than its carrying value resulting in the write down of this property to its estimated fair value at March 31, 2011.

As addressed in Note 2, “Acquisitions,” we applied fair value concepts in estimating and allocating the fair value of the ASOP Properties in accordance with purchase accounting for business combinations. The inputs to the estimated fair values of the assets acquired and liabilities assumed are described in Note 2.

(8) COMMITMENTS AND CONTINGENCIES

We maintain restricted escrow funds in a trust for future abandonment 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 completion of qualifying abandonment activities at our East Bay field. At June 30, 2011, we had $6.0 million remaining in restricted escrow funds for decommissioning work in our East Bay field, which 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 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 sheets as of June 30, 2011.

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.

(9) NEW ACCOUNTING PRONOUNCEMENTS

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs” (“ASU 2011-04”). ASU 2011-04 changes some fair value measurement principles under U.S. GAAP including a change in the valuation premise and the application of premiums and discounts. It also contains certain new disclosure requirements. It is effective for interim and annual periods beginning after December 15, 2011.

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income” (“ASU 2011-05”), which provides the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011 and will be applied retrospectively.

(10) SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In connection with the 8.25% Notes offering described in Note 5, the Guarantors, which include all of our existing 100% owned, direct and indirect domestic subsidiaries (other than immaterial subsidiaries), fully and unconditionally guaranteed, jointly and severally, the payment obligations under our 8.25% Notes and will guarantee the payment obligations under the exchange notes. The following supplemental financial information sets forth, on a consolidating basis, the balance sheets, statements of operations and cash flow information for Energy Partners, Ltd. (Parent Company Only) and for the Guarantors. We have not presented separate financial statements and other disclosures concerning the Guarantors because management has determined that such information is not material to investors.

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

Supplemental Condensed Consolidating Balance Sheet

As of June 30, 2011


	Parent Company Only			Guarantors			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	76,228		$	—		$	—		$	76,228
Accounts receivable		76,911			196			(45,945	)		31,162
Other current assets		7,258			1,674			—			8,932

Total current assets		160,397			1,870			(45,945	)		116,322
Property and equipment		750,063			217,356			—			967,419
Less accumulated depreciation, depletion and amortization		(187,719	)		(40,589	)		—			(228,308	)

Net property and equipment		562,344			176,767			—			739,111
Investment in affiliates		81,792			—			(81,792	)		—
Notes receivable, long-term		—			69,000			(69,000	)		—
Other assets		13,519			—			—			13,519

		818,052			247,637			(196,737	)		868,952

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	60,788		$	53,857		$	(45,945	)	$	68,700
Fair value of commodity derivative instruments		5,604			—			—			5,604

Total current liabilities		66,392			53,857			(45,945	)		74,304
Long-term debt		204,046			69,000			(69,000	)		204,046
Other liabilities		62,603			42,988			—			105,591

		333,041			165,845			(114,945	)		383,941
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		40			98			(98	)		40
Additional paid-in capital		503,965			84,900			(84,900	)		503,965
Retained earnings		(18,986	)		(3,209	)		3,209			(18,986	)
Treasury stock, at cost		(8	)		—			—			(8	)

Total stockholders’ equity		485,011			81,792			(81,792	)		485,011

		818,052			247,637			(196,737	)		868,952

Supplemental Condensed Consolidating Balance Sheet

As of December 31, 2010


	Parent Company Only			Guarantors			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	33,553		$	—		$	—		$	33,553
Accounts receivable		73,040			259			(49,768	)		23,531
Other current assets		4,508			1,674			—			6,182

Total current assets		111,101			1,933			(49,768	)		63,266
Property and equipment		512,569			206,578			—			719,147
Less accumulated depreciation, depletion and amortization		(137,284	)		(30,771	)		—			(168,055	)

Net property and equipment		375,285			175,807			—			551,092
Investment in affiliates		76,236			—			(76,236	)		—
Notes receivable, long-term		—			69,000			(69,000	)		—
Other assets		12,548			—			—			12,548

		575,170			246,740			(195,004	)		626,906

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	50,756		$	62,666		$	(49,768	)	$	63,654
Fair value of commodity derivative instruments		12,320			—			—			12,320

Total current liabilities		63,076			62,666			(49,768	)		75,974
Long-term debt		—			69,000			(69,000	)		—
Other liabilities		38,978			38,838			—			77,816

		102,054			170,504			(118,768	)		153,790
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		40			98			(98	)		40
Additional paid-in capital		502,556			84,900			(84,900	)		502,556
Retained earnings		(29,480	)		(8,765	)		8,765			(29,480	)

Total stockholders’ equity		473,116			76,236			(76,236	)		473,116

		575,170			246,740			(195,004	)		626,906

Supplemental Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2011


	Parent Company Only			Guarantors			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	67,249		$	25,549		$	—		$	92,798
Other		3,751			31			(3,750	)		32

		71,000			25,580			(3,750	)		92,830
Costs and expenses:
Lease operating expenses		12,460			5,448			—			17,908
Taxes, other than on earnings		231			3,464			—			3,695
Exploration expenditures, dry hole cost and impairments		3,631			77			—			3,708
Depreciation, depletion, amortization and accretion		22,471			6,855			—			29,326
General and administrative		4,688			3,858			(3,750	)		4,796
Other expenses		2,139			(1	)		—			2,138

Total costs and expenses		45,620			19,701			(3,750	)		61,571

Income from operations		25,380			5,879			—			31,259

Other income (expense):
Interest expense, net		(4,957	)		—			—			(4,957	)
Gain on derivative instruments		13,831			—			—			13,831
Income from equity investments		3,663			—			(3,663	)		—

Income before income taxes		37,917			5,879			(3,663	)		40,133
Deferred income tax expense		(12,914	)		(2,216	)		—			(15,130	)

Net income	$	25,003		$	3,663		$	(3,663	)	$	25,003

Supplemental Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2010


	Parent Company Only			Guarantors			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	43,393		$	14,770		$	—		$	58,163
Other		3,753			31			(3,750	)		34

		47,146			14,801			(3,750	)		58,197
Costs and expenses:
Lease operating expenses		9,612			4,063			—			13,675
Taxes, other than on earnings		532			1,744			—			2,276
Exploration expenditures, dry hole cost and impairments		11,668			—			—			11,668
Depreciation, depletion, amortization and accretion		24,049			5,279			—			29,328
General and administrative		4,801			3,824			(3,750	)		4,875
Other expenses		1,052			—			—			1,052

Total costs and expenses		51,714			14,910			(3,750	)		62,874

Loss from operations		(4,568	)		(109	)		—			(4,677	)

Other income (expense):
Interest expense, net		(3,857	)		—			—			(3,857	)
Gain on derivative instruments		6,957			—			—			6,957
Loss on early extinguishment of debt		(5,627	)		—			—			(5,627	)
Loss from equity investments		(70	)		—			70			—

Loss before income taxes		(7,165	)		(109	)		70			(7,204	)
Deferred income tax benefit		2,555			39			—			2,594

Net loss	$	(4,610	)	$	(70	)	$	70		$	(4,610	)

Supplemental Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2011


	Parent Company Only			Guarantors			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	113,812		$	46,201		$	—		$	160,013
Other		7,504			62			(7,500	)		66

		121,316			46,263			(7,500	)		160,079
Costs and expenses:
Lease operating expenses		23,491			9,748			—			33,239
Taxes, other than on earnings		596			6,417			—			7,013
Exploration expenditures, dry hole cost and impairments		14,839			205			—			15,044
Depreciation, depletion, amortization and accretion		40,719			13,245			—			53,964
General and administrative		9,863			7,720			(7,500	)		10,083
Other expenses		2,393			10			—			2,403

Total costs and expenses		91,901			37,345			(7,500	)		121,746

Income from operations		29,415			8,918			—			38,333

Other income (expense):
Interest expense, net		(7,417	)		—			—			(7,417	)
Loss on derivative instruments		(11,694	)		—			—			(11,694	)
Loss on early extinguishment of debt		(2,377	)		—			—			(2,377	)
Income from equity investments		5,556			—			(5,556	)		—

Income before income taxes		13,483			8,918			(5,556	)		16,845
Deferred income tax expense		(2,989	)		(3,362	)		—			(6,351	)

Net income	$	10,494		$	5,556		$	(5,556	)	$	10,494

Supplemental Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2010


	Parent Company Only			Guarantors			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	100,923		$	27,923		$	—		$	128,846
Other		7,504			66			(7,500	)		70

		108,427			27,989			(7,500	)		128,916
Costs and expenses:
Lease operating expenses		19,945			8,172			—			28,117
Taxes, other than on earnings		1,027			3,286			—			4,313
Exploration expenditures, dry hole cost and impairments		14,291			—			—			14,291
Depreciation, depletion, amortization and accretion		52,478			9,927			—			62,405
General and administrative		8,903			7,660			(7,500	)		9,063
Other expenses		1,293			—			—			1,293

Total costs and expenses		97,937			29,045			(7,500	)		119,482

Income (loss) from operations		10,490			(1,056	)		—			9,434

Other income (expense):
Interest expense, net		(8,050	)		—			—			(8,050	)
Gain on derivative instruments		5,033			—			—			5,033
Loss on early extinguishment of debt		(5,627	)		—			—			(5,627	)
Loss from equity investments		(676	)		—			676			—

Income (loss) before income taxes		1,170			(1,056	)		676			790
Deferred income tax benefit (expense)		(664	)		380			—			(284	)

Net income (loss)	$	506		$	(676	)	$	676		$	506

Supplemental Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2011


	Parent Company Only			Guarantors			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	51,446		$	10,743		$	—	$	62,189
Cash flows provided by (used in) investing activities:
Property acquisitions		(196,350	)		—			—		(196,350	)
Exploration and development expenditures		(12,251	)		(10,743	)		—		(22,994	)
Other property and equipment additions		(361	)		—			—		(361	)
Decrease in restricted cash		2,467			—			—		2,467

Net cash used in investing activities		(206,495	)		(10,743	)		—		(217,238	)
Cash flows provided by (used in) financing activities:
Proceeds from long-term debt		203,794			—			—		203,794
Deferred financing costs		(6,189	)		—			—		(6,189	)
Exercise of stock options		119			—			—		119

Net cash provided by financing activities		197,724			—			—		197,724

Net increase in cash and cash equivalents		42,675			—			—		42,675
Cash and cash equivalents at the beginning of the period		33,553			—			—		33,553

Cash and cash equivalents at the end of the period	$	76,228		$	—		$	—	$	76,228

Supplemental Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2010


	Parent Company Only			Guarantors			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	47,180		$	20,308		$	—	$	67,488
Cash flows provided by (used in) investing activities:
Property acquisitions		(615	)		—			—		(615	)
Exploration and development expenditures		(6,602	)		(20,308	)		—		(26,910	)
Other property and equipment additions		(39	)		—			—		(39	)
Decrease in restricted cash		11,007			—			—		11,007

Net cash provided by (used in) investing activities		3,751			(20,308	)		—		(16,557	)

Cash flows provided by (used in) financing activities:
Proceeds from long-term debt		20,394			—			—		20,394
Repayments of long-term debt		(69,882	)		—			—		(69,882	)

Net cash used in financing activities		(49,488	)		—			—		(49,488	)

Net increase in cash and cash equivalents		1,443			—			—		1,443
Cash and cash equivalents at the beginning of the period		26,745			—			—		26,745

Cash and cash equivalents at the end of the period	$	28,188		$	—		$	—	$	28,188

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 Annual Report on Form 10-K for the year ended December 31, 2010, as amended (the “2010 Annual Report”).

OVERVIEW

We were incorporated as a Delaware corporation in January 1998 and operate in a single segment as an independent oil and natural gas exploration and production company. Our current operations are concentrated in the U.S. Gulf of Mexico shelf focusing on state and federal waters offshore Louisiana, which we consider our core area. We have focused on acquiring and developing assets in this region, as it offers a balanced and expansive array of existing and prospective exploration, exploitation and development opportunities in both established productive horizons and deeper geologic formations.

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 Securities and Exchange Commission (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 2010 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.

Recent Developments

The ASOP Acquisition and Notes Offering. On February 14, 2011, we acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests surrounding the Mississippi River delta and a related gathering system (the “ASOP Properties”) from Anglo-Suisse Offshore Partners, LLC (“ASOP”) for $200.7 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2011 (the “ASOP Acquisition”). As of December 31, 2010, the ASOP Properties had estimated proved reserves of approximately 8.1 Mmboe, of which 84% were oil and 76% were proved developed reserves. Of these proved developed reserves, 88% were oil reserves. The ASOP Properties acquired in the ASOP Acquisition:

•

included 59 producing wells in three complexes;

•

had average daily production of approximately 3,637 Boe per day for the period from February 14, 2011 to June 30, 2011;

•

included 48,106 gross and 37,402 net acres; and

•

included related gathering lines.

The ASOP Acquisition was financed with the proceeds from the sale of $210 million in aggregate principal amount of 8.25% senior notes due 2018 (the “8.25% Notes”) offered to qualified institutional buyers pursuant to Rule 144A promulgated under the Securities Act of 1933, as amended (the “Securities Act”), and to persons outside the United States pursuant to Regulation S promulgated under the Securities Act. After deducting the initial purchasers’ discount and offering

expenses, we realized net proceeds of approximately $202 million. On July 14, 2011, we and our guarantor subsidiaries (the “Guarantors”) filed a registration statement with the SEC, which was declared effective on July 26, 2011, offering to exchange a new series of freely tradable notes having substantially identical terms as the 8.25% Notes (“exchange notes”) for the 8.25% Notes. On February 14, 2011, we also entered into an agreement for a new credit facility. See “—Liquidity and Capital Resources” for more information regarding the 8.25% Notes and the new credit facility.

The ASOP Acquisition provides an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus on oil-weighted assets in our core area of expertise in the Gulf of Mexico shelf. The ASOP Acquisition also provides us with access to infrastructure and extensive acreage, with significant exploitation and development potential. We are pursuing exploitation of the ASOP Properties, including recompletions, well reactivations and development drilling, while we analyze the potential for higher-impact exploration prospects. We operate properties containing approximately 60% of the proved reserves attributable to the ASOP Properties. In conjunction with the ASOP Acquisition, we implemented a three-year commodity price hedging program weighted towards oil to help reduce commodity price risks associated with future oil production.

Overview and Outlook

Our fiscal year 2011 authorized capital budget is $110 to $125 million (excluding the cost of acquiring the ASOP Properties), $90 to $105 million of which is allocated to development of our existing Gulf of Mexico shelf asset base including the ASOP Properties and $20 million of which is allocated to exploration projects. We are also approved to spend approximately $24 million in 2011 on plugging, abandonment and other decommissioning activities. Our key areas of operations and our plans for future exploration and development activities do not include any deepwater areas. 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. This allocation has led us to focus on oil-weighted projects, which has resulted in the maintenance of our upward trend in our oil production volumes as compared with the decline in our natural gas volumes.

We continually review and monitor opportunities to acquire producing properties, leasehold acreage and drilling prospects so that we can act quickly as acquisition opportunities become available. We intend to focus our acquisition strategy on Gulf of Mexico shelf assets that are characterized by production-weighted reserves, seismic coverage and operated positions. We intend to use acquisitions of this type as a key method to replace and grow reserves and production, because we believe this strategy increases production and cash flow visibility while reducing dry hole and exploration risk. We believe our expertise in the Gulf of Mexico shelf and in plugging and abandonment operations allows us to effectively evaluate acquisitions and to operate any properties we eventually acquire.

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 fund any exploration and development expenditures with internally generated cash flows.

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 remain 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 2010 Annual Report and Item 1A of Part II of this Quarterly Report for a more detailed discussion of these risks.

We believe that we possess a core competency in plugging, abandonment and decommissioning operations which allows us to reduce our overall costs in that area of operations, enabling us to achieve our objectives of prudently removing idle infrastructure throughout the remaining productive lives of our fields and, over time, to reduce ongoing lease operating expenses (“LOE”) associated with maintaining idle infrastructure.

Results of Operations

Three Months Ended June 30, 2011

Our operating results for the three months ended June 30, 2011, compared to the three months ended June 30, 2010, reflect significantly higher average selling prices for our oil as well as higher average selling prices for our natural gas. Our product mix reflects a decline in natural gas production and a decline in production of natural gas liquids, which we expect to continue for the remainder of 2011. Our oil production, which includes natural gas liquids, increased due to an increase in production from oil properties, which more than offset the decline in production of natural gas liquids. Additionally, our results for the three months ended June 30, 2011 include production from the recently acquired ASOP Properties of 3,573 Boe per day. We expect our oil production to increase during the remainder of 2011. We also expect our full-year 2011 oil production to increase as compared to our full-year 2010 oil production.

For the three months ended June 30, 2011, our revenues increased 60% as compared to the three months ended June 30, 2010, due primarily to the higher oil sales prices and the increase in oil production. Our overall production volumes, including barrel of oil equivalent natural gas volumes, decreased by 18% for the three months ended June 30, 2011 when compared to the three months ended June 30, 2010. Our Gulf of Mexico shelf production decreased 14% in the three months ended June 30, 2011, as compared to the quarter ended June 30, 2010, due primarily to production declines in our predominantly natural gas fields, partially offset by production from the ASOP Properties and increasing oil production from our East Bay field. In addition, our deepwater production, primarily natural gas, declined 48% for the quarter ended June 30, 2011, as compared to the quarter ended June 30, 2010, primarily due to natural reservoir decline from our deepwater well. Further, we have recently been informed by the operator of this deepwater gas well that production will be curtailed for extended periods during the second half of the year due to third party downstream facility modifications. We expect that our deepwater production will continue to decline in 2011.

Our revenue for the three months ended June 30, 2011 increased 38%, as compared to the three months ended March 31, 2011, resulting from higher oil revenues from increased oil production and higher realized oil prices, partially offset by lower natural gas revenues from the decline in natural gas production, due to our focus on oil-weighted development projects. Oil production volumes were 26% higher in the three months ended June 30, 2011, as compared to the three months ended March 31, 2011, primarily as a result of the acquisition of the oil-weighted ASOP Properties in the middle of the first quarter of 2011 and our continued focus on oil-weighted projects.

In addition to the items addressed above, our net income for the three months ended June 30, 2011, as compared to the net loss for the three months ended June 30, 2010, primarily reflects a decrease in impairments. The net loss for the three months ended June 30, 2010 also includes a $5.6 million loss on extinguishment of debt resulting from redemption of the PIK Notes during that period.

Our effective income tax rate for the three months ended June 30, 2011 and 2010 was 37.7% and 36.0%, respectively. The increase in our effective income tax rate is primarily related to estimated state income taxes.

Six Months Ended June 30, 2011

During the six months ended June 30, 2011, we completed fifteen (15) recompletion operations, twelve (12) of which were successful.

Our operating results for the six months ended June 30, 2011, compared to the six months ended June 30, 2010, reflect significantly higher average selling prices for our oil and lower average selling prices for our natural gas. Our product mix reflects a decline in natural gas production and a decline in production of natural gas liquids, which we expect to continue for the remainder of 2011. Our oil production, which includes natural gas liquids, increased due to an increase in production from oil properties, which more than offset the decline in production of natural gas liquids. Additionally, our results for the six months ended June 30, 2011 include production from the recently acquired ASOP Properties of 3,637 Boe per day.

For the six months ended June 30, 2011, our revenues increased 24% as compared to the six months ended June 30, 2010, due primarily to the higher oil sales prices and the increase in oil production. Our overall production volumes, including barrel of oil equivalent natural gas volumes, decreased by 27% for the six months ended June 30, 2011 when compared to the six months ended June 30, 2010. Our Gulf of Mexico shelf production decreased 25% in the six months ended June 30, 2011, as compared to the six months ended June 30, 2010, due primarily to production declines in our predominantly natural gas fields, partially offset by production from the ASOP Properties and increasing oil production from our East Bay field. In addition, our deepwater production, primarily natural gas, declined 37% for the six months ended June 30, 2011, as compared to the six months ended June 30, 2010, primarily due to natural reservoir decline from our deepwater well.

Our effective income tax rate for the six months ended June 30, 2011 and 2010 was 37.7% and 36.0%, respectively. The increase in our effective income tax rate is primarily related to estimated state income taxes.

RESULTS OF OPERATIONS

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net production (per day):
Oil (Bbls)		8,286			6,411			7,431			6,817
Natural gas (Mcf)		17,383			43,549			20,174			47,220
Total (Boe)		11,183			13,669			10,793			14,687
Average sales prices:
Oil (per Bbl)	$	113.14		$	70.54		$	106.98		$	71.01
Natural gas (per Mcf)		4.74			4.29			4.41			4.82
Total (per Boe)		91.19			46.76			81.90			48.47
Oil and natural gas revenues (in thousands):
Oil	$	85,307		$	41,149		$	143,892		$	87,616
Natural gas		7,491			17,014			16,121			41,230

Total		92,798			58,163			160,013			128,846
Impact of derivatives instruments settled during the period⁽¹⁾:
Oil (per Bbl)	$	(12.55	)	$	(4.66	)	$	(10.97	)	$	(5.17	)
Natural gas (per Mcf)		—		$	0.02			—		$	0.01
Average costs (per Boe):
LOE	$	17.60		$	10.99		$	17.01		$	10.58
Depreciation, depletion and amortization (“DD&A”)		25.08			20.99			23.85			21.05
Accretion of liability for asset retirement obligations		3.74			2.59			3.78			2.42
Taxes, other than on earnings		3.63			1.83			3.59			1.62
General and administrative (“G&A”) expenses		4.71			3.92			5.16			3.41
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil	$	24,853					$	44,386
Changes in production volumes of oil		19,305						11,890

Total increase in oil sales		44,158						56,276
Changes in prices of natural gas	$	1,787					$	(3,506	)
Changes in production volumes of natural gas		(11,310	)					(21,603	)

Total decrease in natural gas sales		(9,523	)					(25,109	)

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

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Revenue and Net Income (Loss)


	Three Months Ended June 30,
	2011		2010
			(in thousands)			$ Change		% Change
Oil and natural gas revenues	$	92,798	$	58,163		$	34,635		60	%
Net income (loss)		25,003		(4,610	)		29,613		NM

NM—Not Meaningful

Our oil and natural gas revenues increased primarily due to a 60% increase in average selling prices for our oil and a 29% increase in oil production in the three months ended June 30, 2011 as compared to the three months ended June 30, 2010, offset by a 60% decline in natural gas production in the three months ended June 30, 2011 as compared to the three months ended June 30, 2010. The percentage of production represented by oil has increased for us. Oil represented 74% of total production for the three months ended June 30, 2011, as compared to 47% of total production for the three months ended June 30, 2010.

Operating Expenses

Our operating expenses primarily consist of the following:


	Three Months Ended June 30,
	2011		2010
			(in thousands)		$ Change			% Change
LOE	$	17,908	$	13,675	$	4,233			31	%
Exploration expenditures and dry hole costs		822		783		39			5	%
Impairments		2,886		10,885		(7,999	)		(73	)%
DD&A, including accretion expense		29,326		29,328		(2	)		—
G&A expenses		4,796		4,875		(79	)		(2	)%
Taxes, other than on earnings		3,695		2,276		1,419			62	%

LOE has increased primarily due to the addition of the ASOP Properties in 2011. The increase in our LOE per Boe is due to the increase in our oil production as a percentage of our total production, which generally has a higher per Boe cost to produce than natural gas. The percentage of our production represented by oil increased from 47% for the three months ended June 30, 2010 to 74% for the three months ended June 30, 2011.

Impairments for the three months ended June 30, 2011 were primarily related to two natural gas 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, 2011. Impairments for the three months ended June 30, 2010 were primarily related to two natural gas 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.

DD&A per Boe increased primarily due to the acquisition of the ASOP Properties which have higher per Boe DD&A rates because they were recorded at estimated fair values at the February 14, 2011 acquisition date.

G&A expenses include non-cash stock based compensation of $0.8 million and $0.6 million in the three months ended June 30, 2011 and 2010, respectively.

Taxes, other than on earnings, increased in the three months ended June 30, 2011 as compared to the three months ended June 30, 2010, due primarily to higher average sales prices for oil (which is taxed based on value).

Other Income and Expense

Interest expense increased in the three months ended June 30, 2011, as compared to the three months ended June 30, 2010. For the three months ended June 30, 2011, our interest expense consists primarily of interest on our 8.25% Notes issued in connection with the ASOP Acquisition. For the three months ended June 30, 2010, our interest expense consisted primarily of interest on the 20% Senior Subordinated Secured PIK Notes due 2014 (the “PIK Notes”) and the term portion of our credit facility, which were issued in connection with our reorganization under Chapter 11 during 2009 and were outstanding during that period. We redeemed all of our outstanding PIK Notes on June 28, 2010.

Other income (expense) in the three months ended June 30, 2011 includes a net gain of $13.8 million consisting of an unrealized gain of $23.3 million due to the change in fair market value of derivative instruments and a loss of $9.5 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, 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.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Revenue and Net Income


	Six Months Ended June 30,
	2011		2010
			(in thousands)		$ Change		% Change
Oil and natural gas revenues	$	160,013	$	128,846	$	31,167		24	%
Net income		10,494		506		9,988		NM

NM—Not Meaningful

Our oil and natural gas revenues increased primarily due to a 51% increase in average selling prices for our oil and a 9% increase in oil production in the six months ended June 30, 2011 as compared to the six months ended June 30, 2010, offset in part by a 57% decline in natural gas production in the six months ended June 30, 2011 as compared to the six months ended June 30, 2010. The percentage of production represented by oil has increased for us. Oil represented 69% of total production for the six months ended June 30, 2011, as compared to 46% of total production for the six months ended June 30, 2010.

Operating Expenses

Our operating expenses primarily consist of the following:


	Six Months Ended June 30,
	2011		2010
			(in thousands)		$ Change			% Change
LOE	$	33,239	$	28,117	$	5,122			18	%
Exploration expenditures and dry hole costs		1,370		2,637		(1,267	)		(48	)%
Impairments		13,674		11,654		2,020			17	%
DD&A, including accretion expense		53,964		62,405		(8,441	)		(14	)%
G&A expenses		10,083		9,063		1,020			11	%
Taxes, other than on earnings		7,013		4,313		2,700			63	%

LOE has increased primarily due to the addition of the ASOP Properties in 2011. The increase in our LOE per Boe is due to the increase in our oil production, which generally has a higher per Boe cost to produce than natural gas. The percentage of our production represented by oil increased from 46% for the six months ended June 30, 2010 to 69% for the six months ended June 30, 2011.

Exploration expenditures in the six months ended June 30, 2011 includes $0.6 million of delay rentals. In the six months ended June 30, 2010, we drilled one (1) exploratory dry hole 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.

Impairment expense for the six months ended June 30, 2011 was primarily related to reservoir performance at one of our natural gas producing fields where a production zone depleted prematurely. In the same field we experienced mechanical difficulties attempting to access a behind-pipe zone and currently do not expect that the behind-pipe reserves will be economically recoverable. This field was determined to have future net cash flows less than its carrying value resulting in the write down of this property to its estimated fair value at March 31, 2011. Impairment expense for the six months ended June 30, 2010 was primarily related to two natural gas 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.

DD&A declined as a result of the overall Boe production declines described above. DD&A per Boe increased primarily due to the acquisition of the ASOP Properties which have higher per Boe DD&A rates because they were recorded at estimated fair values at the February 14, 2011 acquisition date.

G&A expenses, which include non-cash stock based compensation of $1.3 million and $0.7 million in the six months ended June 30, 2011 and 2010, respectively, increased in the six months ended June 30, 2011, as compared to the six months ended June 30, 2010, primarily as a result of costs incurred in our acquisition efforts in the first quarter of 2011 and the increase in non-cash stock based compensation. Acquisition costs related to the ASOP Acquisition were $0.5 million in the six months ended June 30, 2011.

Taxes, other than on earnings, increased in the six months ended June 30, 2011 as compared to the six months ended June 30, 2010, due primarily to higher average sales prices for oil (which is taxed based on value).

Other Income and Expense

Interest expense decreased in the six months ended June 30, 2011, as compared to the six months ended June 30, 2010. For the six months ended June 30, 2011, our interest expense consists primarily of interest on our 8.25% Notes issued in connection with the ASOP Acquisition. For the six months ended June 30, 2010, interest expense consisted primarily of interest expense on our PIK Notes and the term portion of our credit facility, which were outstanding during that period. We redeemed all of our outstanding PIK Notes on June 28, 2010.

Other income (expense) in the six months ended June 30, 2011 includes a net loss of $11.7 million consisting of an unrealized gain of $3.1 million due to the change in fair market value of derivative instruments and a loss of $14.8 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, 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.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

ASOP Acquisition and Notes Offering. On February 14, 2011, we issued $210 million in aggregate principal amount of the 8.25% Notes. We used the net proceeds from the offering of the 8.25% Notes of $202 million, after deducting the initial purchasers’ discount and offering expenses payable by us, to acquire the ASOP Properties for a purchase price of $200.7 million, before adjustments to reflect an economic effective date of January 1, 2011, and for general corporate purposes. The 8.25% Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest on outstanding notes payable semi-annually, in arrears, on February 15 and August 15 of each year, commencing on August 15, 2011. The 8.25% Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Notes will mature on February 15, 2018. For more information on our 8.25% Notes, see Note 5, “Indebtedness,” of our condensed consolidated financial statements contained in Part I, Item 1 of this Quarterly Report.

New Senior Credit Facility. On February 14, 2011, we entered into our new credit facility with BMO Capital Markets, as lead arranger, Bank of Montreal, as administrative agent and a lender. Under the terms of the credit agreement, our new credit facility established a revolving credit facility with a four-year term that may be used for revolving credit loans and letters of credit up to an aggregate principal amount of $250.0 million, subject to an initial borrowing base of $150.0 million. The new credit facility is secured by substantially all of our assets, including mortgages on at least 85% of our oil and gas properties and the stock of certain wholly-owned subsidiaries. The borrowing base under the new credit facility has been determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special and regular semi-annual redeterminations. We were subject to our first borrowing base semi-annual redetermination in May 2011, and our borrowing base has been reaffirmed at $150 million. Our borrowing base remains at $150.0 million until redetermined. Borrowings under our new credit facility bear interest ranging from a base rate plus a margin of 1.00% to 2.00% on base rate borrowings and LIBOR plus a margin of 2.00% to 3.00% on LIBOR borrowings. We had no amounts drawn under our new credit facility at June 30, 2011.

Sources and Uses of Capital. As of June 30, 2011, we had cash and cash equivalents of $76.2 million and no borrowings outstanding under our new credit facility. At the closing of our 8.25% Notes offering on February 14, 2011, our prior credit facility was replaced with our new credit facility, which has a borrowing base of $150.0 million. There is no term loan component in our new credit facility.

We believe our expertise in the Gulf of Mexico shelf and in plugging and abandonment operations allows us to effectively evaluate acquisitions and to operate any properties we eventually acquire. Our deepwater assets do not fit with our long-term strategy, and there are no current plans to develop these interests. As such, we may monetize or trade these assets.

At June 30, 2011, we had working capital of $42.0 million, compared to a working capital deficit of $12.7 million at December 31, 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.

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 $15.0 million and, with accumulated interest, had increased to $16.7 million at December 31, 2008. We have made draws to date of $10.7 million, with $2.5 million drawn in 2011. We were able to draw from the trust upon the authorization, and subsequent completion, of qualifying abandonment activities at our East Bay field. As of the date of this Quarterly Report, we had $6.0 million remaining in restricted escrow funds for decommissioning work in our East Bay field, which 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.

The BOEMRE 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 “Risk Factors” in Part II, Item 1A of this Quarterly Report and in Part I, Item 1A of our 2010 Annual Report.

Analysis of Cash Flows—Six Months Ended June 30, 2011

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


	Six Months Ended June 30,
	2011			2010
Cash flows provided by operating activities	$	62,189		$	67,488
Cash flows used in investing activities		(217,238	)		(16,557	)
Cash flows provided by (used in) financing activities		197,724			(49,488	)

The decrease in our 2011 cash flows from operations primarily reflects increases in working capital and plugging, abandonment and decommissioning activities during the six months ended June 30, 2011, as compared to the six months ended June 30, 2010.

Net cash used in investing activities increased in the six months ended June 30, 2011, as compared to the six months ended June 30, 2010, primarily as a result of our acquisition of the ASOP Properties during the six months ended June 30, 2011.

Net cash provided by financing activities during the six months ended June 30, 2011 reflects $203.8 million of net cash proceeds (before offering expenses of $1.8 million) from the issuance of the 8.25% Notes, partially offset by expenditures of $6.2 million for financing costs primarily associated with our new senior credit facility and the offering expenses associated with our 8.25% Notes. 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 prior credit facility, partially offset by proceeds from the term loan component of our prior credit facility.

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 our new senior credit facility and the Indenture governing the 8.25% Notes, 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.

Disclosures about Contractual Obligations and Commercial Commitments

The following table aggregates the contractual commitments and commercial obligations which affect our financial condition and liquidity position as of June 30, 2011.


	Payments Due by Period
	Total		Six Months Ending December 31, 2011		Two Years Ending December 31, 2013		Two Years Ending December 31, 2015		Thereafter
	(in thousands)
Indebtedness	$	210,000	$	—	$	—	$	—	$	210,000
Interest on indebtedness		121,275		8,663		34,650		34,650		43,312
Operating leases		3,224		312		1,262		1,133		517
Asset retirement obligations including accretion		238,222		3,542		33,595		27,227		173,858

Total contractual obligations	$	572,721	$	12,517	$	69,507	$	63,010	$	427,687

New Accounting Pronouncements

See Note 9 of the condensed consolidated financial statements in Item 1, Part 1 of this Quarterly Report.

Cautionary Statement Concerning Forward Looking Statements

This Quarterly Report contains forward-looking statements within the meaning of, and we intend that such forward-looking statements be subject to the safe harbor provisions of, the U.S. federal securities laws. Forward-looking statements are, by definition, statements that are not historical in nature and relate to possible future events. They may be, but are not necessarily, identified by words such as “will,” “would,” “should,” “likely,” “estimates,” “thinks,” “strives,” “may,” “anticipates,” “expects,” “believes,” “intends,” “goals,” “plans,” or “projects” and similar expressions.

These forward-looking statements reflect our current views with respect to possible future events, are based on various assumptions and are subject to risks and uncertainties. These forward-looking statements are not guarantees or predictions of our future performance, and our actual results and future developments may differ materially from those projected in, and contemplated by, the forward-looking statements. As a result, you should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements. Among the factors that could cause actual results to differ materially are the risks and uncertainties described under Part I, Item 1A, “Risk Factors,” in our 2010 Annual Report, including the following:

•

planned and unplanned capital expenditures;

•

adequacy of capital resources and liquidity including, but not limited to, access to additional capacity under our credit facility;

•

our substantial level of indebtedness;

•

our ability to incur additional indebtedness;

•

volatility in oil and natural gas prices;

•

volatility in the financial and credit markets;

•

changes in general economic conditions;

•

uncertainties in reserve and production estimates;

•

replacing our oil and natural gas reserves;

•

unanticipated recovery or production problems;

•

availability, cost and adequacy of insurance coverage;

•

hurricane and other weather-related interference with business operations;

•

drilling and operating risks;

•

production expense estimates;

•

the impact of derivative positions;

•

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

•

availability of drilling and production equipment and field service providers;

•

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

•

potential costs associated with complying with new or modified regulations promulgated by the BOEMRE;

•

the impact of political and regulatory developments;

•

risks and liabilities associated with acquired properties or business, including the ASOP Properties;

•

our ability to make and integrate acquisitions, including the ASOP Properties;

•

oil and gas prices and competition; and

•

our ability to generate sufficient cash flow to meet our debt service and other obligations.

Many of these factors are beyond our ability to control or predict. Any, or a combination, of these factors could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

For a further list and description of various risks, relevant factors and uncertainties that could cause future results or events to differ materially from those expressed or implied in our forward-looking statements, see “Risk Factors” in Part 1, Item 1A of our 2010 Annual Report and elsewhere in our 2010 Annual Report and elsewhere in this Quarterly Report; our reports and registration statements filed from time to time with the SEC; and other announcements we make from time to time. Given these risks and uncertainties, you should not place undue reliance on these forward-looking statements.

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 new senior credit facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. At June 30, 2011, our total indebtedness outstanding consisted of $204.0 million (net of unamortized original purchasers’ discount of $6.0 million) related to our fixed-rate 8.25% Notes. Borrowings under our new credit facility bear interest ranging from a base rate plus a margin of 1.00% to 2.00% on base rate borrowings and LIBOR plus a margin of 2.00% to 3.00% on LIBOR borrowings. We had no amounts drawn under our new credit facility at June 30, 2011.

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 new senior 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, 2011, 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)
July 2011		5,390		167,100	$	86.08	$	(1,588	)		503		15,600	$	60.00	$	—
August 2011—November 2011		2,059		251,200	$	90.42	$	(1,637	)		1,301		158,700	$	60.00	$	20
December 2011		3,368		104,400	$	90.25	$	(807	)		1,302		40,350	$	60.00	$	12
January 2012—July 2012		2,167		461,500	$	95.33	$	(1,907	)		—		—		—		—
August 2012—November 2012		721		88,000	$	95.74	$	(415	)		—		—		—		—
December 2012		1,161		36,000	$	95.28	$	(190	)		—		—		—		—
January 2013—July 2013		1,703		361,000	$	94.28	$	(2,223	)		—		—		—		—
August 2013—November 2013		426		52,000	$	94.18	$	(322	)		—		—		—		—
December 2013		806		25,000	$	93.98	$	(159	)		—		—		—		—


	Collars
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Strike Price ($/Bbl)		Fair Value (In thousands)
January 2012—July 2012		500		106,500	$	85.00/118.85	$	103
August 2012—November 2012		500		61,000	$	85.00/118.85	$	35
December 2012		500		15,500	$	85.00/118.85	$	6

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, 2011.

Because of their inherent limitations, disclosure controls and procedures may not prevent or detect misstatements. Also, 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 that the degree of compliance with the controls or procedures may deteriorate. 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 internal control over financial reporting during the three months ended June 30, 2011 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 8, “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 2010 Annual Report that could materially affect our business, financial condition or future results. The risks described in this Form 10-Q and in our 2010 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 from our 2010 Annual Report is revised:

We may not be insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, oil pollution, third party liability, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages and losses.

Currently, we have general liability insurance coverage with an annual aggregate limit of $2.0 million and umbrella liability coverage with an aggregate limit of $150.0 million applicable to our working interest. Our general liability policy is subject to a $25,000 per incident deductible. We also have an offshore property physical damage policy that contains a $90.0 million annual aggregate named windstorm limit of which we self-insure approximately 9%. This offshore property physical damage policy is subject to a $2.5 million deductible that applies to non-named windstorm occurrences and a $20 million deductible that applies to named windstorm events. Further, there are sub-limits within the named windstorm annual aggregate limit for re-drill, plugging and abandonment and removal of wreck that range from $10 million to $45 million. Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $20.0 million to $75.0 million per occurrence. Deepwater wells have a coverage limit of $50.0 million per occurrence. Additionally, we maintain $150.0 million in oil pollution liability coverage as required under the Oil Pollution Act of 1990. Our control of well and oil pollution liability policy limits are scaled proportionately to our working interests, except for our deepwater control of well coverage, which limit is to our working interest. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

An operational or hurricane related event may cause damage or liability in excess of our coverage, which might severely impact our financial position. We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event may also cause a significant interruption to our business, which might also severely impact our financial position. For example, we experienced production interruptions in 2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance.

We reevaluate the purchase of insurance, policy limits and terms annually each April. In light of the catastrophic Deepwater Horizon accident in the Gulf of Mexico in April 2010, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

We maintain an Oil Spill Response Plan (the “Plan”) that defines our response requirements and procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by the BOEMRE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. We believe the Plan specifications are consistent with the requirements set forth by the BOEMRE.

The Company has contracted with an emergency and spill response management consultant, which would provide management expertise, personnel and equipment, under the supervision of the Company, in the event of an incident requiring a coordinated response. Additionally, the Company is a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico and has capabilities to simultaneously respond to multiple spills. CGA’s website states that it is the largest oil spill response cooperative in North America. CGA is structured to provide an effective method of staging response equipment and providing spill response for its member

companies in the Gulf of Mexico. CGA has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), a private, not-for-profit marine spill response organization which is funded by the Marine Preservation Association (“MPA”), a member-supported, not-for-profit organization created to assist the petroleum and energy-related industries by addressing problems caused by oil spills on water. MSRC’s website states that it is the largest dedicated oil spill response organization in the United States. MSRC owns and operates a fleet of dedicated Oil Spill Response Vessels (OSRV), ocean-going barges, shallow water skimming systems, other response equipment and enhanced communications capabilities in various regions including the Gulf of Mexico. MSRC maintains CGA’s equipment (currently including, according to CGA’s website, 11 skimming vessels with capacities ranging from 3,000 to 43,000 barrels per day, 17 skimmers with capacities up to 3,770 barrels per day, numerous containment and storage systems including thousands of feet of boom and two fire boom systems, tanks and storage barges, wildlife cleaning and rehabilitation facilities, both aerial and vessel dispersant spray systems and 33,300 gallons of dispersant) at staging points around the Gulf of Mexico in its ready state. In the event of a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.

Additional resources are available to the Company on an as-needed basis other than as a member of CGA, such as those of MSRC. MSRC has oil spill response equipment independent of, and in addition to, CGA’s equipment. MSRC’s capabilities are augmented by a network of over 100 participants in the Spill Team Area Responders (“STARs”) program, an affiliation of environmental response contractors located at over 200 locations throughout the country. MSRC’s equipment currently includes, according to MSRC’s website, 15 oil spill response vessels (in the Gulf of Mexico) with temporary storage for 4,000 barrels of oil and the ability to separate oil and water, 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, 600,000 feet of boom, over 240 skimming systems, six self-propelled skimming vessels, seven mobile communication suites comprising telephone and computer connections and marine, aviation and business band radios, various small crafts and shallow water vessels and two dispersant/spotter aircraft. In the event of a spill, MSRC activates contractors as necessary to provide additional resources or support services requested by its customers.

The response effectiveness, equipment and resources of these companies may change from time-to-time and current information is generally available on the websites of each of these organizations. There can be no assurances that the Company, together with the organizations described above will be able to effectively manage all emergency and/or spill response activities that may arise and any failures to do so may materially adversely impact the Company’s financial position, results of operations and cash flows.

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

SEC File

Number

Exhibit

Filing Date

Filed/

Furnished

Herewith

Form

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

05/06/2010

2.1

Purchase and Sale Agreement dated January 13, 2011, by and between Anglo-Suisse Offshore Partners, LLC and Energy Partners, Ltd.

8-K

001-16179

2.1

01/18/2011

3.1

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

8-A/A

001-16179

3.1

09/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-A/A

001-16179

3.2

09/21/2009

4.1

Indenture by and among Energy Partners, Ltd., as Issuer, the Guarantors named therein and U.S. Bank National Association, as Trustee dated February 14, 2011

8-K

001-16179

4.1

02/15/2011

4.2

Supplemental Indenture by and among Anglo-Suisse Offshore Pipeline Partners, LLC, as a Guarantor, Energy Partners, Ltd., as Issuer, and the other Guarantors named therein and U.S. Bank National Association, as Trustee, dated March 14, 2011

S-4

333-175567

4.2

07/14/2011

10.1†

Offer Letter to W. Mac Jensen, accepted on May 2, 2011

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.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

In accordance with Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q is furnished and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be part of any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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

SEC File

Number

Exhibit

Filing Date

Filed/

Furnished

Herewith

Form

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

05/06/2010

2.1

Purchase and Sale Agreement dated January 13, 2011, by and between Anglo-Suisse Offshore Partners, LLC and Energy Partners, Ltd.

8-K

001-16179

2.1

01/18/2011

3.1

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

8-A/A

001-16179

3.1

09/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-A/A

001-16179

3.2

09/21/2009

4.1

Indenture by and among Energy Partners, Ltd., as Issuer, the Guarantors named therein and U.S. Bank National Association, as Trustee dated February 14, 2011

8-K

001-16179

4.1

02/15/2011

4.2

S-4

333-175567

4.2

07/14/2011

10.1†

Offer Letter to W. Mac Jensen, accepted on May 2, 2011

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.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company).

Smaller reporting company