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 March 31, 2012

¨	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 April 27, 2012, there were 39,232,564 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:		3

Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2012 and December 31, 2011		3

Condensed Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2012 and 2011		4

Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended March 31, 2012 and 2011		5

Notes to Condensed Consolidated Financial Statements (Unaudited)		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. Quantitative and Qualitative Disclosures about Market Risk		23

Item 4. Controls and Procedures		24

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		25

Item 1A. Risk Factors		25

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		25

Item 3. Defaults Upon Senior Securities		25

Item 4. Mine Safety Disclosures		25

Item 5. Other Information		25

Item 6. Exhibits		26

PART I—FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


(In thousands, except share data)	March 31, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	91,420		$	80,128
Trade accounts receivable—net		35,410			31,817
Fair value of commodity derivative instruments		—			587
Deferred tax assets		1,773			—
Prepaid expenses		5,935			11,046

Total current assets		134,538			123,578
Property and equipment, under the successful efforts method of accounting for oil and natural gas properties		1,131,027			1,082,248
Less accumulated depreciation, depletion, amortization and impairments		(331,333	)		(305,110	)

Net property and equipment		799,694			777,138
Restricted cash		6,023			6,023
Other assets		3,033			3,029
Deferred financing costs—net of accumulated amortization of $1,383 at March 31, 2012 and $1,061 at December 31, 2011		5,134			5,452

	$	948,422		$	915,220

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	35,882		$	25,393
Accrued expenses		65,014			58,538
Asset retirement obligations		21,080			25,578
Fair value of commodity derivative instruments		12,790			1,056
Deferred tax liabilities		—			2,823

Total current liabilities		134,766			113,388
Long-term debt		204,568			204,390
Asset retirement obligations		76,840			73,769
Deferred tax liabilities		36,965			31,775
Fair value of commodity derivative instruments		4,411			190
Other		1,128			663

		458,678			424,175
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 1,000,000 shares; no shares issued and outstanding at March 31, 2012 and December 31, 2011		—			—
Common stock, $0.001 par value per share; authorized 75,000,000 shares; shares issued 40,459,715 and 40,326,451 at March 31, 2012 and December 31, 2011, respectively; shares outstanding 39,290,705 and 39,404,106 at March 31, 2012 and December 31, 2011, respectively		40			40
Additional paid-in capital		506,246			505,235
Treasury stock, at cost, 1,169,010 and 922,345 shares at March 31, 2012 and December 31, 2011, respectively		(15,176	)		(11,361	)
Accumulated deficit		(1,366	)		(2,869	)

Total stockholders’ equity		489,744			491,045

	$	948,422		$	915,220

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended March 31,
(In thousands, except per share data)	2012			2011
Revenue:
Oil and natural gas	$	98,772		$	67,215
Other		24			34

		98,796			67,249
Costs and expenses:
Lease operating		18,411			15,331
Transportation		151			135
Exploration expenditures and dry hole costs		14,309			548
Impairments		2,314			10,788
Depreciation, depletion and amortization		23,908			21,063
Accretion of liability for asset retirement obligations		3,148			3,575
General and administrative		5,344			5,287
Taxes, other than on earnings		3,741			3,318
Other		175			130

Total costs and expenses		71,501			60,175

Income from operations		27,295			7,074
Other income (expense):
Interest income		38			10
Interest expense		(4,874	)		(2,470	)
Loss on derivative instruments		(20,062	)		(25,525	)
Loss on early extinguishment of debt		—			(2,377	)

		(24,898	)		(30,362	)
Income (loss) before income taxes		2,397			(23,288	)
Income tax benefit (expense)		(894	)		8,779

Net income (loss)	$	1,503		$	(14,509	)

Basic earnings (loss) per share	$	0.04		$	(0.36	)
Diluted earnings (loss) per share	$	0.04		$	(0.36	)
Weighted average common shares used in computing earnings (loss) per share:
Basic		39,121			40,080
Diluted		39,298			40,080

See accompanying notes to condensed consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Three Months Ended March 31,
(In thousands)	2012			2011
Cash flows from operating activities:
Net income (loss)	$	1,503		$	(14,509	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		23,908			21,063
Accretion of liability for asset retirement obligations		3,148			3,575
Loss on early extinguishment of debt		—			2,377
Unrealized loss on derivative contracts		16,542			20,234
Non-cash compensation		991			502
Deferred income taxes		594			(8,797	)
Exploration expenditures		2,637			115
Impairments		2,314			10,788
Amortization of deferred financing costs and discount on debt		500			246
Other		168			172
Changes in operating assets and liabilities:
Trade accounts receivable		(2,516	)		(12,407	)
Other receivables		—			1,283
Prepaid expenses		5,111			898
Other assets		(4	)		79
Accounts payable and accrued expenses		11,247			(3,760	)
Asset retirement obligations		(9,082	)		(7,033	)

Net cash provided by operating activities		57,061			14,826

Cash flows used in investing activities:
Decrease in restricted cash		—			1,273
Property acquisitions		(88	)		(195,734	)
Exploration and development expenditures		(41,505	)		(7,078	)
Other property and equipment additions		(504	)		(167	)

Net cash used in investing activities		(42,097	)		(201,706	)

Cash flows provided by (used in) financing activities:
Proceeds from indebtedness		—			203,794
Deferred financing costs		(4	)		(6,164	)
Purchase of shares into treasury		(3,668	)		—
Exercise of stock options		—			119

Net cash provided by (used in) financing activities		(3,672	)		197,749

Net increase in cash and cash equivalents		11,292			10,869
Cash and cash equivalents at beginning of period		80,128			33,553

Cash and cash equivalents at end of period	$	91,420		$	44,422

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 March 31, 2012 and for the three-month periods ended March 31, 2012 and March 31, 2011 has not been audited. However, in the opinion of management, all adjustments (which include only normal, recurring adjustments) necessary to present fairly the financial position and results of operations for the periods presented have been included therein. Certain information and footnote disclosures normally in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to rules and regulations of the Securities and Exchange Commission. The condensed consolidated balance sheet at December 31, 2011 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, 2011 (the “2011 Annual Report”). The results of operations and cash flows for the first three months of the year are not necessarily indicative of the results of operations which might be expected for the entire year.

(2) Acquisitions

The ASOP Acquisition

On February 14, 2011, we acquired from Anglo-Suisse Offshore Partners, LLC (“ASOP”) 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”) 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 provided 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. We financed the ASOP Acquisition with the proceeds from the sale of $210 million in aggregate principal amount of the 8.25% senior notes due 2018 (the “8.25% Notes”). After deducting the initial purchasers’ discount and offering expenses, we realized net proceeds of approximately $202 million. 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 table summarizes the estimated values of assets acquired and liabilities assumed and reflects adjustments to purchase price provided for by the purchase and sale agreement totaling approximately $3.8 million to reflect an economic effective date of January 1, 2011.


(In thousands)	January 1, 2011
Oil and natural gas properties	$	221,751
Asset retirement obligations		(24,858	)

Net assets acquired	$	196,893

The Main Pass Acquisition

On November 17, 2011, we acquired certain interests in producing oil and natural gas assets in the shallow-water central Gulf of Mexico shelf (the “Main Pass Interests”) from Stone Energy Offshore, L.L.C. (the “Seller”) for $38.6 million in cash, subject to customary adjustments to reflect the economic effective date of November 1, 2011 (the “Main Pass Acquisition”). The Main Pass Interests consist of additional interests in the Main Pass 296/311 complex that was included in the ASOP Acquisition, along with other unit interests in the Main Pass complex and an interest in a Main Pass 295 primary term lease. We estimate that the proved reserves as of the November 1, 2011 economic effective date totaled approximately 2.6 Mmboe, all of which were proved developed reserves and approximately 96% of which were oil reserves. We funded the Main Pass Acquisition with cash on hand.

The following allocation of the purchase price as of November 1, 2011 is preliminary and includes 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 adjustments to purchase price provided for by the purchase and sale agreement. 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 adjustments to purchase price provided for by the purchase and sale agreement of approximately $0.8 million to reflect an economic effective date of November 1, 2011.


(In thousands)	November 1, 2011
Oil and natural gas properties	$	39,403
Asset retirement obligations		(1,577	)

Net assets acquired	$	37,826

Results of Operations and Pro Forma Information

Revenues and lease operating expenses attributable to the ASOP Properties and the Main Pass Interests for the three months ended March 31, 2012 were $40.4 million and $6.6 million, respectively. Revenues and lease operating expenses attributable to the ASOP Properties for the three months ended March 31, 2011 were $16.5 million and $1.7 million, respectively. We have determined that the presentation of net income attributable to the ASOP Properties and the Main Pass Interests is impracticable due to the integration of the related operations upon acquisition. We incurred fees of approximately $0.5 million related to the ASOP Acquisition, which were included in general and administrative expenses in the accompanying consolidated statement of operations for the three months ended March 31, 2011.

The following supplemental pro forma information presents consolidated results of operations as if the ASOP Acquisition and Main Pass Acquisition had occurred on January 1, 2011. The supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations, b) the statements of revenues and direct operating expenses for the ASOP Properties, which were derived from ASOP’s historical accounting records and c) the statements of revenues and direct operating expenses for the Main Pass Interests, which were derived from the historical accounting records of Seller. This information does not purport to be indicative of results of operations that would have occurred had the acquisition occurred on January 1, 2011, nor is such information indicative of any expected future results of operations.


	Three Months Ended March 31,
	Historical 2012		Pro Forma 2011
	(in thousands, except per share data)
Revenue	$	98,796	$	84,283
Net income (loss)	$	1,503	$	(11,558	)
Basic earnings (loss) per share	$	0.04	$	(0.29	)
Diluted earnings (loss) per share	$	0.04	$	(0.29	)

(3) Earnings per Share

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods.


	Three Months Ended March 31,
	2012			2011
Income (numerator):
Net income (loss)	$	1,503		$	(14,509	)
Net income attributable to participating securities		(9	)		—

Net income (loss) – basic and diluted	$	1,494		$	(14,509	)

Weighted average shares (denominator):
Weighted average shares—basic		39,121			40,080
Dilutive effect of stock options and unvested restricted shares		177			—

Weighted average shares—diluted		39,298			40,080

Basic earnings (loss) per share	$	0.04		$	(0.36	)
Diluted earnings (loss) per share	$	0.04		$	(0.36	)

For the three months ended March 31, 2012, stock options excluded from the diluted earnings per share calculation because they were antidilutive for the period totaled approximately 569,924 weighted average shares. For the three months ended March 31, 2011, the computation of diluted loss per share excludes potentially dilutive stock options and unvested restricted share awards totaling 117,409 weighted average shares because we had a net loss for the period.

(4) Asset Retirement Obligations

Changes in our asset retirement obligations were as follows:


	Three Months Ended March 31, 2012
	(in thousands)
Balance at December 31, 2011	$	99,347
Accretion expense		3,148
Liabilities incurred		121
Revisions		4,386
Liabilities settled		(9,082	)

Balance at March 31, 2012		97,920
Less: End of period, current portion		(21,080	)

End of period, noncurrent portion	$	76,840

(5) Indebtedness

The following table sets forth our indebtedness.


	March 31,		December 31,
(In thousands)	2012		2011
8.25% Senior Notes, face amount of $210.0 million, interest rate of 8.25% payable semi-annually, in arrears on February 15 and August 15 of each year, mature February 15, 2018	$	204,568	$	204,390
Senior Credit Facility, interest rate based on base rate or LIBOR plus a floating spread, maturity date February 14, 2015		—		—

Total indebtedness		204,568		204,390
Current portion of indebtedness		—		—

Noncurrent portion of indebtedness	$	204,568	$	204,390

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 three months ended March 31, 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.

The 8.25% Notes

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. For additional information regarding the 8.25% Notes, see Note 7, “Indebtedness,” of our 2011 Annual Report.

Senior Credit Facility

On February 14, 2011, we entered our senior credit facility with BMO Capital Markets, as lead arranger, and Bank of Montreal, as administrative agent and a lender, and the other lender parties thereto (“Senior Credit Facility”). Upon the closing of our Senior Credit Facility, our then existing credit facility was terminated. The terms of our Senior 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. The maximum amount of letters of credit that may be outstanding at any one time is $20.0 million. 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 Senior Credit Facility by up to an additional $50.0 million to the extent that existing and/or future lenders provide additional commitments. The Senior 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 our Senior 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. As of May 1, 2012, we completed our semi-annual redetermination and our borrowing base remains at $200.0 million. Borrowings under our Senior 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 Senior Credit Facility at March 31, 2012 and December 31, 2011. For additional information regarding our Senior Credit Facility, see Note 7, “Indebtedness,” of our 2011 Annual Report.

(6) Derivative Instruments and Hedging Activities

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 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 instruments are carried at their fair value on the condensed consolidated balance sheets as Fair value of commodity derivative instruments, and all unrealized and realized gains and losses are recorded in Gain (loss) on derivative instruments in Other income (expense) in the condensed consolidated statements of operations. See Note 7 for information regarding fair values of our derivative instruments.

The following table sets forth our derivative instruments outstanding as of March 31, 2012.

Oil Contracts


	Fixed-Price Swaps
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Swap Price ($/Bbl)
April 2012—July 2012		3,725		454,500	$	99.99
August 2012—November 2012		2,721		332,000	$	103.76
December 2012		3,161		98,000	$	102.47
January 2013—July 2013		3,103		657,800	$	100.19
August 2013—November 2013		1,826		222,800	$	103.69
December 2013		2,206		68,400	$	101.98


	Collars
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Strike Price ($/Bbl)
April 2012—July 2012		1,000		122,000	$	87.50/123.18
August 2012—November 2012		1,000		122,000	$	87.50/123.18
December 2012		1,000		31,000	$	87.50/123.18
January 2013—July 2013		500		106,000	$	90.00/129.40
August 2013—November 2013		500		61,000	$	90.00/129.40
December 2013		500		15,500	$	90.00/129.40

The following table presents information about the components of our loss on derivative instruments:


	Three Months Ended March 31,
	2012			2011
	(in thousands)
Derivative contracts:
Unrealized loss due to change in fair market value	$	(16,542	)	$	(20,234	)
Realized loss on settlement		(3,520	)		(5,291	)

Total loss on derivative instruments	$	(20,062	)	$	(25,525	)

(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. In May 2011, the Financial Accounting Standards Board (the “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”), which became effective for us in the current interim period. ASU 2011-04 includes additional guidance related to fair value measurement principles and additional disclosure requirements. The impact of adopting ASU 2011-04 was immaterial.

As of March 31, 2012 and December 31, 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 our derivative instruments were measured according to the market approach or, if necessary, the income approach using price inputs published by NYMEX and IntercontinentalExchange, Inc., or ICE. These price inputs include settled exchange prices and quoted prices for assets and liabilities similar to those held by us and meet the definition of Level 2 inputs within the fair value hierarchy. The following table sets forth our financial assets and liabilities that are accounted for at fair value on a recurring basis:


	March 31, 2012		December 31, 2011
	(in thousands)
Assets:
Fair value of commodity derivative instruments	$	—	$	587
Liabilities:
Fair value of commodity derivative instruments	$	17,201	$	1,246

As of March 31, 2012 and December 31, 2011, the carrying amount of our 8.25% Notes was $204.6 million and $204.4 million, respectively, which reflects the $210.0 million face amount, net of the unamortized amount of initial purchasers’ discount of $5.4 million and $5.6 million at March 31, 2012 and December 31, 2011, respectively. As of March 31, 2012 and December 31, 2011, we estimated the fair value of the 8.25% Notes at approximately $212.7 million and $202.7 million, respectively, based on quoted prices, which are Level 1 inputs within the fair value hierarchy.

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, which is 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 are based on our estimates of future events, including projections of future oil and natural gas sales prices, amounts of recoverable oil and natural gas reserves, timing of future production, future costs to develop and produce our oil and natural gas and discount factors. These inputs meet the definition of Level 3 inputs within the fair value hierarchy. Impairments for the three months ended March 31, 2012 were primarily due to the decline in our estimate of future natural gas prices affecting one of our natural gas producing fields. 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, 2012. Impairments for the three months ended March 31, 2011 were primarily related to reservoir performance at one of our natural gas producing fields. 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 and Main Pass Interests 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 over time 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 March 31, 2012, 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 March 31, 2012 and December 31, 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 December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 201): Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 requires disclosure of information about offsetting and related arrangements to enable users of financial statements to understand the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. The required disclosures are effective for our annual report for the year ending December 31, 2013 and for interim periods within that year. We have not yet completed our review of the required disclosures; however, we expect the impact on our reporting to be immaterial.

(10) Supplemental Condensed Consolidating Financial Information

In connection with the 8.25% Notes offering described in Note 5, all of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries) (the “Guarantor Subsidiaries”) jointly, severally and unconditionally guaranteed the payment obligations under our 8.25% 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 Guarantor Subsidiaries. We have not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries because management has determined that such information is not material to investors.

The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. 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 March 31, 2012


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	91,420		$	—		$	—		$	91,420
Accounts receivable		96,225			130			(60,945	)		35,410
Other current assets		7,708			—			—			7,708

Total current assets		195,353			130			(60,945	)		134,538
Property and equipment		872,809			258,218			—			1,131,027
Less accumulated depreciation, depletion, amortization and impairments		(273,484	)		(57,849	)		—			(331,333	)

Net property and equipment		599,325			200,369			—			766,694
Investment in affiliates		99,199			—			(99,199	)		—
Notes receivable, long-term		—			69,000			(69,000	)		—
Other assets		14,190			—			—			14,190

		908,067			269,499			(229,144	)		948,422

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	114,981		$	67,940		$	(60,945	)	$	121,976
Fair value of commodity derivative instruments		12,790			—			—			12,790

Total current liabilities		127,771			67,940			(60,945	)		134,766
Long-term debt		204,568			69,000			(69,000	)		204,568
Other liabilities		85,984			33,360			—			119,344

		418,323			170,300			(129,945	)		458,678
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		40			98			(98	)		40
Additional paid-in capital		506,246			84,900			(84,900	)		506,246
Retained earnings (accumulated deficit)		(1,366	)		14,198			(14,198	)		(1,366	)
Treasury stock, at cost		(15,176	)		—			—			(15,176	)

Total stockholders’ equity		489,744			99,199			(99,199	)		489,744

		908,067			269,499			(229,144	)		948,422

Supplemental Condensed Consolidating Balance Sheet

As of December 31, 2011


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	80,128		$	—		$	—		$	80,128
Accounts receivable		93,882			131			(62,196	)		31,817
Other current assets		11,633			—			—			11,633

Total current assets		185,643			131			(62,196	)		123,578
Property and equipment		833,932			248,316			—			1,082,248
Less accumulated depreciation, depletion, amortization and impairments		(251,948	)		(53,162	)		—			(305,110	)

Net property and equipment		581,984			195,154			—			777,138
Investment in affiliates		91,768			—			(91,768	)		—
Notes receivable, long-term		—			69,000			(69,000	)		—
Other assets		14,504			—			—			14,504

		873,899			264,285			(222,964	)		915,220

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	99,096		$	72,609		$	(62,196	)	$	109,509
Deferred tax liabilities		2,823			—			—			2,823
Fair value of commodity derivative instruments		1,056			—			—			1,056

Total current liabilities		102,975			72,609			(62,196	)		113,388
Long-term debt		204,390			69,000			(69,000	)		204,390
Other liabilities		75,489			30,908			—			106,397

		382,854			172,517			(131,196	)		424,175
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		40			98			(98	)		40
Additional paid-in capital		505,235			84,900			(84,900	)		505,235
Treasury stock		(11,361	)		—			—			(11,361	)
Retained earnings (accumulated deficit)		(2,869	)		6,767			(6,767	)		(2,869	)

Total stockholders’ equity		491,045			91,768			(91,768	)		491,045

		873,899			264,285			(222,964	)		915,220

Supplemental Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2012


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	69,275		$	29,497		$	—		$	98,772
Other		3,752			22			(3,750	)		24

		73,027			29,519			(3,750	)		98,796
Costs and expenses:
Lease operating expenses		13,947			4,464			—			18,411
Taxes, other than on earnings		244			3,497			—			3,741
Exploration expenditures, dry hole costs and impairments		16,625			(2	)		—			16,623
Depreciation, depletion, amortization and accretion		21,214			5,842			—			27,056
General and administrative		5,229			3,865			(3,750	)		5,344
Other expenses		325			1			—			326

Total costs and expenses		57,584			17,667			(3,750	)		71,501

Income from operations		15,443			11,852			—			27,295

Other income (expense):
Interest expense, net		(4,836	)		—			—			(4,836	)
Loss on derivative instruments		(20,062	)		—			—			(20,062	)
Income from equity investments		7,431			—			(7,431	)		—

Income (loss) before income taxes		(2,024	)		11,852			(7,431	)		2,397
Income taxes		3,527			(4,421	)		—			(894	)

Net income (loss)	$	1,503		$	7,431		$	(7,431	)	$	1,503

Supplemental Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2011


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	46,563		$	20,652		$	—		$	67,215
Other		3,753			31			(3,750	)		34

		50,316			20,683			(3,750	)		67,249
Costs and expenses:
Lease operating expenses		11,031			4,300			—			15,331
Taxes, other than on earnings		365			2,953			—			3,318
Exploration expenditures, dry hole costs and impairments		11,208			128			—			11,336
Depreciation, depletion, amortization and accretion		18,248			6,390			—			24,638
General and administrative		5,175			3,862			(3,750	)		5,287
Other expenses		254			11			—			265

Total costs and expenses		46,281			17,644			(3,750	)		60,175

Income from operations		4,035			3,039			—			7,074

Other income (expense):
Interest expense, net		(2,460	)		—			—			(2,460	)
Loss on derivative instruments		(25,525	)		—			—			(25,525	)
Loss on early extinguishment of debt		(2,377	)		—			—			(2,377	)
Income from equity investments		1,893			—			(1,893	)		—

Income (loss) before income taxes		(24,434	)		3,039			(1,893	)		(23,288	)
Income taxes		9,925			(1,146	)		—			8,779

Net income (loss)	$	(14,509	)	$	1,893		$	(1,893	)	$	(14,509	)

Supplemental Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2012


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	47,160		$	9,901		$	—	$	57,061
Cash flows provided by (used in) investing activities:
Property acquisitions		(88	)		—			—		(88	)
Exploration and development expenditures		(31,604	)		(9,901	)		—		(41,505	)
Other property and equipment additions		(504	)		—			—		(504	)

Net cash used in investing activities		(32,196	)		(9,901	)		—		(42,097	)
Cash flows provided by (used in) financing activities:
Deferred financing costs		(4	)		—			—		(4	)
Purchase of shares into treasury		(3,668	)		—			—		(3,668	)

Net cash used in financing activities		(3,672	)		—			—		(3,672	)

Net increase in cash and cash equivalents		11,292			—			—		11,292
Cash and cash equivalents at the beginning of the period		80,128			—			—		80,128

Cash and cash equivalents at the end of the period	$	91,420		$	—		$	—	$	91,420

Supplemental Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2011


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	11,120		$	3,706		$	—	$	14,826
Cash flows provided by (used in) investing activities:
Property acquisitions		(195,734	)		—			—		(195,734	)
Exploration and development expenditures		(3,372	)		(3,706	)		—		(7,078	)
Other property and equipment additions		(167	)		—			—		(167	)
Decrease in restricted cash		1,273			—			—		1,273

Net cash used in investing activities		(198,000	)		(3,706	)		—		(201,706	)
Cash flows provided by (used in) financing activities:
Deferred financing costs		(6,164	)		—			—		(6,164	)
Proceeds from long-term debt		203,794			—			—		203,794
Exercise of stock options		119			—			—		119

Net cash provided by financing activities		197,749			—			—		197,749

Net increase in cash and cash equivalents		10,869			—			—		10,869
Cash and cash equivalents at the beginning of the period		33,553			—			—		33,553

Cash and cash equivalents at the end of the period	$	44,422		$	—		$	—	$	44,422

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 2011 Annual Report and under the heading “Risk Factors” in Item 1A of Part II of this Quarterly 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 2011 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 of oil 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.

Overview and Outlook

Our fiscal year 2012 capital budget is $184 million, of which $114 million is allocated to development activities and $70 million to exploration projects, including seismic purchases, within existing core field areas. We recently acquired additional 2-D and 3-D seismic data sets regionally across our current offshore operating areas and extending onshore Louisiana where the geology is characterized by the same productive horizons and structural features. Additionally, we plan to spend approximately $27 million in 2012 on plugging, abandonment and other decommissioning activities.

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 a trend of increasing oil production volumes and declining natural gas production 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, operated positions and the ability to consolidate interests in existing properties. 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 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.

We are also focused on the development of a core competency in plugging, abandonment and decommissioning operations, which will enable 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.

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 have a material adverse effect on 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 2011 Annual Report and Item 1A of Part II of this Quarterly Report for a more detailed discussion of these risks.

Results of Operations

During the three months ended March 31, 2012, we completed three (3) development drilling operations, all of which were successful, and nine (9) recompletion operations, seven (7) of which were successful. We also completed two (2) exploratory drilling operations, which were determined to be unsuccessful.

Our operating results for the three months ended March 31, 2012, compared to the three months ended March 31, 2011, reflect a 43% increase in oil production and higher average selling prices for our oil, partially offset by lower natural gas production and lower average selling prices for our natural gas. Our product mix for the three months ended March 31, 2012 was 79% oil (including natural gas liquids) compared to 63% for the three months ended March 31, 2011. Our results for the three months ended March 31, 2012 include production from the acquired ASOP Properties and Main Pass Interests of 3,994 Boe per day, compared to results for the quarter ended March 31, 2011, which include production from the ASOP Properties for the period from February 14, 2011 to March 31, 2011, reflecting only a 1,884 Boe per day impact on the production rate in the prior period. We expect our full-year 2012 oil production to increase as compared to our full-year 2011 oil production.

For the three months ended March 31, 2012, our revenues increased 47% as compared to the three months ended March 31, 2011, due primarily to the 43% increase in oil production and higher oil sales prices. Our overall production volumes increased by 14% for the three months ended March 31, 2012 when compared to the three months ended March 31, 2011. Our Gulf of Mexico shelf production increased 26% in the three months ended March 31, 2012, as compared to the three months ended March 31, 2011, due primarily to production from the ASOP Properties and Main Pass Interests, partially offset by production declines in our predominantly natural gas fields. In addition, our deepwater production, primarily natural gas, was curtailed during the three months ended March 31, 2012 due to third party downstream facility modifications.

In addition to the items addressed above, our net income for the three months ended March 31, 2012 as compared to a net loss for the three months ended March 31, 2011 includes significant exploration expenditures, primarily due to the area-wide 2-D and 3-D seismic purchases totaling $10.3 million during the first quarter of 2012. The net loss for the three months ended March 31, 2011 reflects impairments of $10.8 million and a $2.4 million loss on early extinguishment of debt as a result of the termination of our prior credit facility.

Our effective income tax rate for the three months ended March 31, 2012 was 37.3%. Our effective income tax rate for the three months ended March 31, 2011 was 37.7%. The decrease 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 March 31,
	2012			2011
Net production (per day):
Oil (Bbls)		9,386			6,567
Natural gas (Mcf)		14,950			22,995
Total (Boe)		11,878			10,400
Average sales prices:
Oil (per Bbl)	$	111.68		$	99.12
Natural gas (per Mcf)		2.48			4.17
Total (per Boe)		91.38			71.81
Oil and natural gas revenues (in thousands):
Oil	$	95,397		$	58,585
Natural gas		3,375			8,630

Total		98,772			67,215
Impact of derivatives instruments settled during the period per Bbl of oil⁽¹⁾	$	(4.12	)	$	(8.95	)
Average costs (per Boe):
LOE	$	17.03		$	16.38
Depreciation, depletion and amortization (“DD&A”)		22.12			22.50
Accretion of liability for asset retirement obligations		2.91			3.82
Taxes, other than on earnings		3.46			3.54
General and administrative (“G&A”) expenses		4.94			5.65
Increase (decrease) in oil and natural gas revenues due to (in thousands):
Changes in prices of oil	$	7,426
Changes in production volumes of oil		29,386

Total increase in oil sales		36,812
Changes in prices of natural gas	$	(3,496	)
Changes in production volumes of natural gas		(1,759	)

Total decrease in natural gas sales		(5,255	)

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

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Revenue and Net Income (Loss)


	Three Months Ended March 31
	2012		2011
						$ Change		% Change
Oil and natural gas revenues	$	98,772	$	67,215		$	31,557		47	%
Net income (loss)		1,503		(14,509	)		NM		NM

NM – Not Meaningful

Our oil and natural gas revenues increased primarily as a result of the 43% increase in oil production and the 13% increase in average selling prices for our oil production in the three months ended March 31, 2012, as compared to the three months ended March 31, 2011, offset in part by a 35% decline in natural gas production and a 41% decline in average selling prices for our natural gas in the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Oil represented 79% of total production for the three months ended March 31, 2012 as compared to 63% of total production for the three months ended March 31, 2011.

Operating Expenses

Our operating expenses primarily consist of the following:


	Three Months Ended March 31,
	2012		2011
			(in thousands)		$ Change			% Change
LOE	$	18,411	$	15,331	$	3,080			20	%
Exploration expenditures and dry hole costs		14,309		548		13,761			NM
Impairments		2,314		10,788		(8,474	)		NM
DD&A, including accretion expense		27,056		24,638		2,418			10	%
G&A expenses		5,344		5,287		57			1	%
Taxes, other than on earnings		3,741		3,318		423			13	%

NM – Not Meaningful

LOE increased for the three months ended March 31, 2012, as compared to the three months ended March 31, 2011, primarily due to the 2011 acquisitions of the ASOP Properties and Main Pass Interests.

During the three months ended March 31, 2012, we recorded approximately $2.6 million of dry hole costs, primarily associated with two exploratory wells which reached their target depths in January 2012 and were determined to be unsuccessful. In addition, exploration expenditures during the three months ended March 31, 2012 include $10.3 million of seismic expense.

Impairments for the three months ended March 31, 2012 were primarily due to the decline in our estimate of future natural gas prices, which affected one of our natural gas producing fields. 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, 2012. Impairments for the three months ended March 31, 2011 were primarily related to reservoir performance at one of our natural gas producing fields. 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.

G&A expenses, excluding non-cash share-based compensation of $1.0 million and $0.5 million in the three months ended March 31, 2012 and 2011, respectively, were lower in the three months ended March 31, 2012, as compared to the three months ended March 31, 2011, primarily because the 2011 period includes $0.5 million in acquisition costs related to the ASOP Acquisition.

Taxes, other than on earnings, increased in the three months ended March 31, 2012, as compared to the three months ended March 31, 2011, 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 March 31, 2012, as compared to the three months ended March 31, 2011. For the three months ended March 31, 2012 and 2011, our interest expense consists primarily of interest on our 8.25% Notes issued in connection with the ASOP Acquisition on February 14, 2011.

Other income (expense) in the three months ended March 31, 2012 includes a net loss on derivative instruments of $20.0 million consisting of an unrealized loss of $16.5 million due to the change in fair market value of derivative instruments which were to be settled in the future and a realized loss of $3.5 million on derivative instruments settled during the quarter primarily from the impact of higher oil prices during 2012. Other income (expense) in the three months ended March 31, 2011 includes a net loss on derivative instruments of $25.5 million consisting of an unrealized loss of $20.2 million due to the change in fair market value of derivative instruments to be settled in the future and a realized loss of $5.3 million on derivative instruments settled during the quarter primarily from the impact of higher oil prices during 2011.

During the three months ended March 31, 2011, we terminated our prior credit facility resulting 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.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

At March 31, 2012, we had unrestricted cash on hand of approximately $91.4 million and no amounts drawn under our credit facility, which currently has a borrowing base of $200 million. Our fiscal year 2012 capital budget is $184 million, of which $114 million is allocated to development activities and $70 million to exploration projects within existing core field areas including seismic purchases. Additionally, we plan to spend approximately $27 million in 2012 on plugging, abandonment and other decommissioning activities. We intend to finance our capital expenditure budget and plugging and abandonment expenditures with cash flow from operations.

Sources and Uses of Capital

As of March 31, 2012, we had cash and cash equivalents of $91.4 million and no amounts drawn under our Senior Credit Facility (described below). At the closing of our 8.25% Notes offering on February 14, 2011, our prior credit facility was replaced with our Senior Credit Facility, which had an initial borrowing base of $150.0 million and was increased to $200.0 million in November 2011.

Capital Expenditures. During the three months ended March 31, 2012, we incurred costs of approximately $57.3 million on development and exploration activities, including $10.3 million on the seismic purchases previously described. We also spent approximately $9.1 million on plugging, abandonment and other decommissioning activities during the quarter.

Acquisitions. We may fund future acquisitions with a combination of cash on hand, borrowings on our credit facility and issuances of one or more debt and equity securities under our universal shelf registration statement that became effective under the Securities Act of 1933 in July 2011.

Share Repurchase Program. In August 2011, the Board of Directors authorized a program for the repurchase of our outstanding common stock for up to an aggregate cash purchase price of $20.0 million and recently increased the program to $40.0 million. Under the program, we have repurchased 1,199,000 shares at an aggregate cash purchase price of approximately $15.9 million, including 180,000 shares purchased for approximately $3.1 million during 2012. Such shares are held in treasury and could be used to provide available shares for possible resale in future public or private offerings and our employee benefit plans. The repurchases have been, and will be, carried out in accordance with certain volume, timing and price constraints imposed by the SEC’s rules applicable to such transactions. The amount, timing and price of purchases otherwise depend on market conditions and other factors.

Working Capital. At March 31, 2012, we had a working capital deficit of $0.2 million, compared to working capital of $10.2 million at December 31, 2011. 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.

Restricted Cash. 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. 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 Bureau of Ocean Energy Management (“BOEM”), the Bureau of Safety and Environmental Enforcement (“BSEE”) 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 2011 Annual Report.

8.25% Notes. 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 estimated 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 7, “Indebtedness,” of our consolidated financial statements contained in Part II, Item 8 of our 2011 Annual Report.

Senior Credit Facility. On February 14, 2011, we entered our Senior Credit Facility with BMO Capital Markets, as lead arranger, Bank of Montreal, as administrative agent and a lender, and the other lenders party thereto. The terms of our Senior 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 million. The maximum amount of the letters of credit that may be outstanding at any one time is $20 million. 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 Senior Credit Facility by up to an additional $50 million to the extent that existing and/or future lenders provide additional commitments. The Senior 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 our Senior 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. As of May 1, 2012, we completed our

semi-annual redetermination and our borrowing base remains at $200 million. Borrowings under our Senior 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 Senior Credit Facility at March 31, 2012 and December 31, 2011.

Terminated Credit Facility. We terminated the then existing prior credit facility in connection with entering into our current credit facility described above, resulting 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.

Analysis of Cash Flows – Three Months Ended March 31, 2012

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


	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities	$	57,061		$	14,826
Cash flows used in investing activities		(42,097	)		(201,706	)
Cash flows provided by (used in) financing activities		(3,672	)		197,749

The increase in our 2012 cash flows from operating activities primarily reflects increases in revenues due to the increase in our oil production and oil prices, partially offset by decreases in natural gas revenues during the three months ended March 31, 2012, as compared to the three months ended March 31, 2011.

Net cash used in investing activities was lower in the three months ended March 31, 2012, as compared to the three months ended March 31, 2011, due to our acquisition of the ASOP Properties during the three months ended March 31, 2011, partially offset by an increase in exploration and development expenditures in the three months ended March 31, 2012.

Net cash used in financing activities during the three months ended March 31, 2012 reflects the settlements of purchases of shares of our common stock (which have been kept as treasury shares) pursuant to our repurchase program during the three months ended March 31, 2012. Net cash provided by financing activities during the three months ended March 31, 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 Senior Credit Facility and the offering expenses associated with our 8.25% Notes.

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 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.

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, “Risk Factors” in Item 1A of Part I of our 2011 Annual Report and Item 1A of Part II of this Quarterly 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 BOEM and BSEE;

•

the impact of political and regulatory developments;

•

risks and liabilities associated with acquired properties or businesses;

•

our ability to make and integrate acquisitions;

•

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 2011 Annual Report and elsewhere in our 2011 Annual Report and Part II, Item 1A of this Quarterly 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 Senior Credit Facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. Borrowings under our Senior 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 Senior Credit Facility at March 31, 2012 or December 31, 2011. At March 31, 2012, our total indebtedness outstanding consisted of $204.6 million (net of unamortized original purchaser’s discount of $5.4 million) related to our fixed-rate 8.25% Notes, which mature on February 15, 2018. The estimated fair value of our 8.25% Notes was approximately $212.7 million at March 31, 2012.

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 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 March 31, 2012, the following derivative instruments were outstanding:

Oil Contracts


	Fixed-Price Swaps
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Swap Price ($/Bbl)		Fair Value (In thousands)
April 2012—July 2012		3,725		454,500	$	99.99	$	(4,974	)
August 2012—November 2012		2,721		332,000	$	103.76	$	(3,627	)
December 2012		3,161		98,000	$	102.47	$	(974	)
January 2013—July 2013		3,103		657,800	$	100.19	$	(5,522	)
August 2013—November 2013		1,826		222,800	$	103.69	$	(1,083	)
December 2013		2,206		68,400	$	101.98	$	(281	)


	Collars
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Strike Price ($/Bbl)		Fair Value (In thousands)
April 2012—July 2012		1,000		122,000	$	87.50/123.18	$	(156	)
August 2012—November 2012		1,000		122,000	$	87.50/123.18	$	(282	)
December 2012		1,000		31,000	$	87.50/123.18	$	(71	)
January 2013—July 2013		500		106,000	$	90.00/129.40	$	(202	)
August 2013—November 2013		500		61,000	$	90.00/129.40	$	(31	)
December 2013		500		15,500	$	90.00/129.40	$	2

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 March 31, 2012.

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 March 31, 2012 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 risk factor below and 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 2011 Annual Report that could materially affect our business, financial condition or future results. The risks described in this Quarterly Report on Form 10-Q and in our 2011 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 have a material adverse effect on our business, financial condition and future results.

The risk factor below is an update to the risk factor titled “We may not be insured against all of the operating risks to which our business is exposed” found under “Item 1A. – Risk Factors” in our 2011 Annual Report.

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/excess liabilities 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 offshore property physical damage and operators extra expense policies that contain an aggregate of $175.7 million of named windstorm limit of which we self-insure approximately 9%. Recoveries from these policies are subject to a $2.5 million deductible that applies to non-named windstorm occurrences and a $20.0 million deductible that applies to named windstorm events except for East Bay central facilities and rental compressor losses, which are subject to a 1.5% deductible. Further, there are scheduled sub-limits within the named windstorm annual aggregate limit for re-drill, non-blowout plugging and abandonment and excess removal of wreck. 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, to which the $50.0 million limit applies 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. 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 will generally be approved by the BSEE 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 BSEE.

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 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 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 in various warehouse locations (currently including, according to CGA’s website, 14 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 more than 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 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; two dispersant aircraft; and four 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.

Issuer Purchases of Equity Securities


Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (1) (in thousands)
March 2012		180,000	$	17.13		180,000	$	24,105

(1)

On August 29, 2011, we announced that the Board of Directors authorized a program for the repurchase of shares of our outstanding common stock for up to an aggregate cash purchase price of $20.0 million. On May 2, 2012, the Board of Directors authorized an increase to the program from $20.0 million to $40.0 million. We are funding the stock repurchases out of cash on hand. The repurchased shares will be accumulated and held in treasury. The repurchases are carried out in accordance with certain volume, timing and price constraints imposed by the SEC’s rules applicable to such transactions. The amount, timing and price of purchases otherwise depend on market conditions and other factors.

Item 3.

DEFAULTS UPON SENIOR SECURITIES.

None

Item 4.

MINE SAFETY DISCLOSURES.

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, 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†

Employment Agreement dated as of February 1, 2012, between Energy Partners, Ltd. and John H. Peper

10-K

001-16179

10.24

03/08/2012

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 Annual Report on Form 10-K 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†

Employment Agreement dated as of February 1, 2012, between Energy Partners, Ltd. and John H. Peper

10-K

001-16179

10.24

03/08/2012

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