Energy XXI Ltd - FORM 10-Q

Attached files

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EX-31.1 - EXHIBIT 31-1 - Energy XXI Ltd	ex31_1.htm
EX-32.2 - EXHIBIT 32-2 - Energy XXI Ltd	ex32_2.htm
EX-32.1 - EXHIBIT 32-1 - Energy XXI Ltd	ex32_1.htm
EX-31.2 - EXHIBIT 31-2 - Energy XXI Ltd	ex31_2.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011

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

For the transition period from

Commission File Number: 001-33628

ENERGY XXI (BERMUDA) LIMITED

(Exact name of registrant as specified in its charter)

Bermuda		98-0499286
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

Canon’s Court, 22 Victoria Street, PO Box HM
1179, Hamilton HM EX, Bermuda		N/A
(Address of principal executive offices)		(Zip Code)

(441) 295-2244 (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 þNo ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes ¨No ¨

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

Large accelerated filer ¨ Accelerated filerþ

Non-accelerated filer ¨ Smaller Reporting Company¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No þ

As of April 28, 2011, there were 74,259,235 shares outstanding of the registrant’s common stock, par value $0.005 per share.

ENERGY XXI (BERMUDA) LIMITED

TABLE OF CONTENTS

		Page

GLOSSARY OF TERMS		3

PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements	5
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	43
ITEM 4.	Controls and Procedures	44

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	45
ITEM 1A.	Risk Factors	45
ITEM 6.	Exhibits	46
SIGNATURES		47
EXHIBIT INDEX		48

GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this document:

Bbls	Standard barrel containing 42 U.S. gallons	MMBbls	One million Bbls
Mcf	One thousand cubic feet	MMcf	One million cubic feet
Btu	One British thermal unit	MMBtu	One million Btu
BOE	Barrel of oil equivalent	MBOE	One thousand BOEs
DD&A	Depreciation, Depletion and Amortization	MMBOE	One million BOEs

Call options are contracts giving the holder (purchaser) the right, but not the obligation, to buy (call) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Cash-flow hedges are derivative instruments used to mitigate the risk of variability in cash flows from crude oil and natural gas sales due to changes in market prices. Examples of such derivative instruments include fixed-price swaps, fixed-price swaps combined with basis swaps, purchased put options, costless collars (purchased put options and written call options) and producer three-ways (purchased put spreads and written call options). These derivative instruments either fix the price a party receives for its production or, in the case of option contracts, set a minimum price or a price within a fixed range.

Completion refers to the work performed and the installation of permanent equipment for the production of natural gas and crude oil from a recently drilled well.

Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well, is acreage that is allocated or assignable to producing wells or wells capable of production. For a complete definition of developed oil and gas reserves, refer to Rule 4-10(a)-(6) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.

Dry hole is an exploratory or development well that does not produce oil or gas in commercial quantities.

Exploitation is drilling wells in areas proven to be productive.

Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.

Fair-value hedges are derivative instruments used to hedge or offset the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment. For example, a contract is entered into whereby a commitment is made to deliver to a customer a specified quantity of crude oil or natural gas at a fixed price over a specified period of time. In order to hedge against changes in the fair value of these commitments, a party enters into swap agreements with financial counterparties that allow the party to receive market prices for the committed specified quantities included in the physical contract.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

Gross acres or gross wells are the total acres or wells in which a working interest is owned.

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Horizon is a zone of a particular formation or that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

Independent oil and gas company is a company that is primarily engaged in the exploration and production sector of the oil and gas business.

Lease operating or well operating expenses are expenses incurred to operate the wells and equipment on a producing lease.

Natural gas is converted into one BOE based on 6 Mcf of gas to one barrel of oil.

Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the Company’s working interest percentage in the properties.

Operating costs include direct and indirect expenses, including general and administrative expenses, incurred to manage, operate and maintain our wells and related equipment and facilities.

Plugging and abandonment refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from a stratum will not escape into another or to the surface. Regulations of many states and the federal government require the plugging of abandoned wells.

Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. For a complete definition of production costs, please refer to Rule 4-10(a) (20) of Regulation S-X as promulgated by the SEC.

Productive well is a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and gas reserves, refer to Rule 4-10(a) (22) of Regulation S-X as promulgated by the SEC.

Put options are contracts giving the holder (purchaser) the right, but not the obligation, to sell (put) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of undeveloped oil and gas reserves, refer to Rule 4-10(a)(31) of Regulation S-X as promulgated by the SEC.

Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover is the operations on a producing well to restore or increase production and such costs are expensed. If the operations add new proved reserves, such costs are capitalized.

Zone is a stratigraphic interval containing one or more reservoirs.

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PART I - FINANCIAL INFORMATION

ITEM 1. Financial Statements

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	March 31,			June 30,
	2011			2010
ASSETS	(Unaudited)
Current Assets
Cash and cash equivalents	$	33,106		$	14,224
Accounts receivable
Oil and natural gas sales		125,908			68,675
Joint interest billings		5,943			4,388
Insurance and other		2,839			4,471
Prepaid expenses and other current assets		26,040			34,479
Derivative financial instruments		1,265			19,757
Total Current Assets		195,101			145,994

Property and Equipment, net of accumulated depreciation, depletion and amortization
Oil and natural gas properties - full cost method of accounting, including $451.4 million and $144.3 million unevaluated properties at March 31, 2011 and June 30, 2010, respectively		2,594,970			1,378,222
Other property and equipment		8,364			8,028
Total Property and Equipment		2,603,334			1,386,250
Other Assets
Derivative financial instruments		2,655			14,610
Deferred income taxes		51,402			—
Debt issuance costs, net of accumulated amortization and other assets		36,959			19,637
Total Other Assets		91,016			34,247
Total Assets	$	2,889,451		$	1,566,491
LIABILITIES
Current Liabilities
Accounts payable	$	118,200		$	87,103
Accrued liabilities		101,348			68,783
Asset retirement obligations		30,919			35,154
Derivative financial instruments		123,355			1,701
Current maturities of long-term debt		2,709			2,518
Total Current Liabilities		376,531			195,259
Long-term debt, less current maturities		1,228,094			772,082
Deferred income taxes		—			37,215
Asset retirement obligations, net of current portion		310,081			124,123
Derivative financial instruments		128,606			511
Other liabilities		8,207			740
Total Liabilities		2,051,519			1,129,930
Commitments and Contingencies (Note 14)
Stockholders’ Equity
7.25 % Preferred stock, $0.01 par value, 2,500,000 shares authorized and 96,500 and 1,100,000 shares issued and outstanding at March 31, 2011 and June 30, 2010, respectively.		1			11
5.625 % Preferred stock, $0.001 par value, 2,500,000 shares authorized and 1,150,000 and -0- shares issued and outstanding at March 31, 2011 and June 30, 2010, respectively.		1			—
Common stock, $0.005 par value, 200,000,000 shares authorized and 74,269,851 and 50,819,109 shares issued and 74,269,198 and 50,636,719 shares outstanding at March 31, 2011 and June 30, 2010, respectively		371			254
Additional paid-in capital		1,474,122			901,457
Accumulated deficit		(491,967	)		(492,867	)
Accumulated other comprehensive income (loss), net of income tax expense (benefit)		(144,596	)		27,706
Total Stockholders’ Equity		837,932			436,561
Total Liabilities and Stockholders’ Equity	$	2,889,451		$	1,566,491

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, except per share information)

(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31,
	2011			2010			2011			2010

Revenues
Oil sales	$	216,711		$	114,095		$	479,080		$	278,438
Natural gas sales		41,925			36,032			97,509			81,102
Total Revenues		258,636			150,127			576,589			359,540

Costs and Expenses
Lease operating expense		70,066			40,832			159,487			101,307
Production taxes		721			870			2,131			3,152
Depreciation, depletion and amortization		91,301			50,761			208,300			131,084
Accretion of asset retirement obligations		9,907			6,335			22,229			17,641
General and administrative expense		23,155			14,452			57,538			36,540
Loss (gain) on derivative financial instruments		(619	)		314			(3,395	)		(4,009	)
Total Costs and Expenses		194,531			113,564			446,290			285,715

Operating Income		64,105			36,563			130,299			73,825

Other Income (Expense)
Bridge loan commitment fees		—			—			(4,500	)		—
Loss on retirement of debt		(12,199	)		—			(17,383	)		—
Other income		15			13			176			29,657
Interest expense		(31,418	)		(21,837	)		(74,992	)		(67,144	)
Total Other Income (Expense)		(43,602	)		(21,824	)		(96,699	)		(37,487	)

Income Before Income Taxes		20,503			14,739			33,600			36,338

Income Tax Expense		2,132			3,651			4,162			21,104

Net Income		18,371			11,088			29,438			15,234
Induced Conversion of Preferred Stock		44			—			19,840			—
Preferred Stock Dividends		4,278			1,994			8,698			2,326
Net Income Attributable to Common Stockholders	$	14,049		$	9,094		$	900		$	12,908

Net Income Per Share Attributable to Common Stockholders
Basic	$	0.19		$	0.18		$	0.01		$	0.34
Diluted	$	0.19		$	0.18		$	0.01		$	0.34

Weighted Average Number of Common Shares Outstanding
Basic		74,221			50,713			63,490			37,790
Diluted		74,421			60,730			63,732			38,126

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31,
	2011			2010			2011			2010

Cash Flows From Operating Activities
Net income	$	18,371		$	11,088		$	29,438		$	15,234
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization		91,301			50,761			208,300			131,084
Deferred income tax expense		2,132			3,651			4,162			21,104
Change in derivative financial instruments
Proceeds from sale of derivative instruments		—			5,000			42,577			5,000
Other – net		(9,773	)		(8,577	)		(25,987	)		(25,692	)
Accretion of asset retirement obligations		9,907			6,335			22,229			17,641
Amortization of deferred gain on debt and debt discount and premium		(389	)		(2,748	)		(43,521	)		(33,615	)
Amortization and write-off of debt issuance costs		6,568			1,584			10,822			6,043
Stock-based compensation		946			839			3,126			2,580
Payment of interest in-kind		—			—			2,225			—
Changes in operating assets and liabilities
Accounts receivable		(14,732	)		17,242			(54,703	)		(21,143	)
Prepaid expenses and other current assets		10,717			6,218			8,439			(14,967	)
Settlement of asset retirement obligations		(19,537	)		(16,374	)		(54,155	)		(58,823	)
Accounts payable and accrued liabilities		50,744			29,092			70,756			35,994
Net Cash Provided by Operating Activities		146,255			104,111			223,708			80,440

Cash Flows from Investing Activities
Acquisitions		(9,113	)		(846	)		(1,022,124	)		(275,364	)
Capital expenditures		(61,571	)		(36,827	)		(190,196	)		(98,689	)
Insurance payments received		—			807			—			53,985
Transfer to restricted cash		—			—			—			(2,160	)
Proceeds from the sale of properties		75			—			475			—
Other		(52	)		(40	)		31			94
Net Cash Used in Investing Activities		(70,661	)		(36,906	)		(1,211,814	)		(322,134	)

Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		1,187			—			562,090			294,468
Conversion of preferred stock to common		(44	)		—			(11,956	)		—
Dividends to shareholders		(6,153	)		(1,994	)		(8,326	)		(1,994	)
Proceeds from long-term debt		378,526			22,687			1,538,526			98,525
Payments on long-term debt		(458,084	)		(82,582	)		(1,044,851	)		(206,025	)
Payments for debt issuance costs and other		2,089			(10,469	)		(28,495	)		(14,088	)
Net Cash Provided by (Used in) Financing Activities		(82,479	)		(72,358	)		1,006,988			170,886

Net Increase (Decrease) in Cash and Cash Equivalents		(6,885	)		(5,153	)		18,882			(70,808	)

Cash and Cash Equivalents, beginning of period		39,991			23,270			14,224			88,925

Cash and Cash Equivalents, end of period	$	33,106		$	18,117		$	33,106		$	18,117

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI (BERMUDA) LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation

Nature of Operations. Energy XXI (Bermuda) Limited was incorporated in Bermuda on July 25, 2005. We are headquartered in Houston, Texas. We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico.

References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries, including Energy XXI (US Holdings) Limited (“Energy XXI Holdings”), Energy XXI Insurance Limited (“EXXI Insurance” and, together with Energy XXI (Bermuda) Limited and Energy XXI Holdings, our “Bermuda Companies”), Energy XXI, Inc. (“EXXI Corp.”), Energy XXI USA, Inc. (“EXXI USA”), Energy XXI GOM, LLC (“GOM”), Energy XXI Gulf Coast, Inc. (“EGC”), Energy XXI Services, LLC (“EXXI Services”), Energy XXI Texas Onshore, LLC (“Texas Onshore”), Energy XXI Pipeline, LLC (“EXXI Pipeline”) and Energy XXI Onshore, LLC (“Onshore” and, together with EXXI Corp., EXXI USA, GOM, EGC, EXXI Services, EXXI Pipeline and Texas Onshore, our “U.S. Companies”).

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income, stockholders’ equity or cash flows.

Interim Financial Statements. The accompanying consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the U.S. for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. For further information, please refer to the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended June 30, 2010.

Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment. While we believe that the estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.

Note 2 – Recent Accounting Pronouncements

We disclose the existence and potential effect of accounting standards issued but not yet adopted by us or recently adopted by us with respect to accounting standards that may have an impact on us in the future.

Fair Value Measurements and Disclosures. The FASB has issued new guidance on improving disclosures about fair value measurements. The new guidance requires certain new disclosures and clarifies some existing disclosure requirements about fair value measurement. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, the new guidance now requires:

·	A reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and

·	In the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements.

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In addition, the new guidance clarifies the requirements of the following existing disclosures:

·	For purposes of reporting fair value measurement for each class of assets and liabilities, a reporting entity needs to use judgment in determining the appropriate classes of assets and liabilities; and

·	A reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements.

The new guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. We adopted the new guidance effective January 1, 2010. The implementation of this standard did not have a material impact on our consolidated financial position and results of operations.

Updates to Oil and Gas Accounting Rules. In January 2010, the FASB issued its updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries—Oil and Gas with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008. We adopted the new rules effective June 30, 2010. The new rules are applied prospectively as a change in estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in the Final Rule include, but are not limited to:


	•	Oil and gas reserves must be reported using the average price over the prior 12-month period, rather than year-end prices;

	•	Companies are allowed to report, on an optional basis, probable and possible reserves;

	•	Non-traditional reserves, such as oil and gas extracted from coal and shales, are included in the definition of “oil and gas producing activities”;

	•	Companies are permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

	•	Companies are required to disclose, in narrative form, additional details on their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs;

	•	Companies are required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.

Note 3 –Oil and Gas Properties

Oil and Gas Properties. We use the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

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Ceiling Test. Under the full cost method of accounting, we are required to perform a “ceiling test” each quarter that determines a limit on the book value of our oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties and future development costs, exceeds the present value of estimated future net cash flows discounted at 10%, net of related tax effects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. Future net cash flows are based on the average commodity prices realized over the preceding twelve-month period and exclude future cash outflows related to estimated abandonment costs. As of the reported balance sheet date, capitalized costs of oil and gas producing properties may not exceed the full cost limitation calculated under the above described rule.

Note 4 – Acquisitions

ExxonMobil Acquisition

On December 17, 2010, we closed on the acquisition of certain shallow-water Gulf of Mexico shelf oil and natural gas interests from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). The transaction was funded through a combination of cash on hand, including proceeds from common and preferred equity offerings (Note 12), borrowings against our $700 million corporate revolver, as amended, and proceeds from the $750 million private placement by our operating subsidiary, EGC, of 9.25% senior unsecured notes due 2017. The purchase remains subject to certain post-closing adjustments to reflect actual operating results since the effective date of December 1, 2010.

The ExxonMobil Acquisition was accounted for under the purchase method of accounting. Accordingly, we conducted a preliminary assessment of the net assets acquired and recognized provisional amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The accounting for the business combination is not complete; adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as we complete a more detailed analysis of this acquisition and additional information is obtained about the facts and circumstances that existed as of the acquisition date.

Revenues and expenses related to the ExxonMobil properties for the third quarter ended March 31, 2011 and from the closing date (December 17, 2010) to March 31, 2011 are included in the March 31, 2011 results of operations.

Pursuant to the Purchase and Sale Agreement (the “PSA”), ExxonMobil reserved a 5% overriding royalty interest in the ExxonMobil Properties for production from depths below approximately 16,000 feet. In addition, the PSA required us to post a $225 million letter of credit, which we posted under our revolving credit facility, in favor of ExxonMobil to guarantee our obligation to plug and abandon the ExxonMobil Properties in the future.

The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 17, 2010 (in thousands):

Oil and natural gas properties– evaluated	$	935,801
Oil and natural gas properties– unevaluated		289,711
Net working capital		101
Asset retirement obligations		(204,512	)
Cash paid	$	1,021,101

Net working capital includes gas imbalance receivables and payables and ad valorem taxes payable.

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The preliminary fair values of evaluated and unevaluated oil and gas properties and asset retirement obligation liabilities were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

The following amounts of the ExxonMobil Properties’ revenue and earnings included in our consolidated statement of operations for the three and nine months ended March 31, 2011 (in thousands).

	Revenue		Earnings (1)

ExxonMobil Acquisition properties from January 1, 2011 through March 31, 2011	$	99,388	$	71,548

ExxonMobil Acquisition properties from December 17, 2010 through March 31, 2011	$	117,395	$	84,915

(1)	Earnings includes revenue less production costs.

Mit Acquisition

On December 22, 2009, we closed on the acquisition of certain Gulf of Mexico shelf oil and natural gas interests from MitEnergy Upstream LLC, a subsidiary of Mitsui & Co., Ltd. (the “Mit Acquisition”), for cash consideration of $276.2 million. For accounting purposes, we recorded this acquisition as effective November 20, 2009, the date that we gained control of the assets acquired and liabilities assumed. We financed the Mit Acquisition through proceeds received from common and perpetual preferred stock offerings (See Note 12).

The Mit Acquisition was accounted for under the purchase method of accounting. Accordingly, we conducted an assessment of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Transaction, transition and integration costs associated with this acquisition were expensed as incurred.

The Mit Acquisition involved mirror-image non-operated interests in the same group of properties we purchased from Pogo Producing Company in June 2007. These properties include 30 fields of which production is approximately 77% crude oil and 80% of which was already operated by us. Offshore leases included in this acquisition total nearly 33,000 net acres.

The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 20, 2009 (in thousands):

Oil and natural gas properties– evaluated	$	292,609
Oil and natural gas properties– unevaluated		41,987
Net working capital		4,237
Asset retirement obligations		(62,604	)
Cash paid	$	276,229

Net working capital includes gas imbalance receivables and payables and ad valorem taxes payable.

The fair values of evaluated and unevaluated oil and gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

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ExxonMobil and Mit Pro Forma Information

The summarized unaudited pro forma financial information for the nine months ended March 31, 2011 and 2010, respectively, assumes that the ExxonMobil and Mit Acquisitions had occurred on July 1, 2009. These unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed the acquisitions as of July 1, 2009 or the results that will be attained in the future (in thousands).

	Revenue		Earnings (1)

Supplemental pro forma for July 1, 2010 through March 31, 2011	$	748,323	$	541,566

Supplemental pro forma for July 1, 2009 through March 31, 2010	$	717,094	$	513,874

(1)	Earnings includes revenue less production costs.

Note 5 – Property and Equipment

Property and equipment consists of the following (in thousands):

	March 31, 2011		June 30, 2010
Oil and gas properties
Proved properties	$	3,791,359	$	2,675,308
Less: Accumulated depreciation, depletion and amortization		1,647,744		1,441,396
Proved properties—net		2,143,615		1,233,912
Unproved properties		451,355		144,310
Oil and gas properties—net		2,594,970		1,378,222

Other property and equipment		17,843		15,641
Less: Accumulated depreciation		9,479		7,613
Other property and equipment—net		8,364		8,028
Total property and equipment	$	2,603,334	$	1,386,250

Note 6 – Long-term Debt

Long-term debt consists of the following (in thousands):

	March 31, 2011		June 30, 2010

Revolving credit facility	$	119,527	$	109,457
9.25% Senior Notes due 2017		750,000		—
7.75% Senior Notes due 2019		250,000		—
10% Senior Notes due 2013		106,338		276,500
16% Second Lien Notes due 2014 (Exchange Offer)		—		341,319
16% Second Lien Notes due 2014 (Private Placement)		—		44,210
Total 16% Second Lien Notes due 2014		—		385,529
Put premium financing		4,222		2,317
Capital lease obligation		716		797
Total debt		1,230,803		774,600
Less current maturities		2,709		2,518
Total long-term debt	$	1,228,094	$	772,082

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Maturities of long-term debt as of March 31, 2011 are as follows (in thousands):

Twelve Months Ending March 31,

2012	$	2,709
2013		121,573
2014		106,521
2015		—
2016		—
Thereafter		1,000,000
Total	$	1,230,803

Revolving Credit Facility

This facility was entered into by our subsidiary, EGC. This facility, as amended, has a borrowing capacity of $925 million and matures December 31, 2014, provided that in the event that all or any portion of the 10% Senior Notes remain outstanding ninety days prior to June 15, 2013, then such maturity date is March 15, 2013. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. The current borrowing base is $700 million. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.50% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.50%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.

The revolving credit facility requires EGC to maintain certain financial covenants. Specifically, EGC may not permit the following under the revolving credit facility: (1) EGC’s total leverage ratio to be more than 3.5 to 1.0, (2) EGC’s interest rate coverage ratio to be less than 3.0 to 1.0, (3) EGC’s secured debt ratio to be more than 2.5 to 1.0, and (4) EGC’s current ratio (in each case as defined in our revolving credit facility) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, changes in control, our ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of March 31, 2011, we are in compliance with all covenants.

On October 15, 2010, EGC and its lenders entered into the Seventh Amendment to Amended and Restated First Lien Credit Agreement (“Seventh Amendment”).

The Seventh Amendment modifications to the First Lien Credit Agreement include;

Allowing the establishment of a Swing Line Loan Commitment in an amount initially set at $15 million which is carved out of the $350 million First Lien Credit Agreement borrowing base. The amounts ultimately available under the Swing Line can be adjusted upward or downward by the lenders and EGC under certain conditions.

2)	Allow for a one-time payment by EGC to us or our subsidiaries of up to $25 million for the purpose of paying premiums or other payments associated with inducing the early conversion of our 7.25% preferred stock.

3)	Allow payments by EGC to us or our subsidiaries of up to $9 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock.

On November 17, 2010, we entered into an Eighth Amendment to Amended and Restated First Lien Credit Agreement to our revolving credit facility (the “Eighth Amendment”). The Eighth Amendment modifies the First Lien Credit Agreement and includes the following: (a) the increase of debt incurrence provisions to allow for an incremental unsecured debt basket of up to $1.0 billion, (b) the redetermination of the borrowing base to $700 million, (c) the increase of the notional amount of the revolving credit facility to $925 million, (d) the increase of the letter of credit sublimit to $300 million, and (e) the extension of the maturity date to December 31, 2014, (March 31, 2013 if any of the 10% Senior Notes remain outstanding). The Eighth Amendment was deemed effective when all conditions precedent had been met, including the closing of the ExxonMobil Acquisition. All of these conditions were met on December 17, 2010.

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High Yield Facilities

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Senior Notes”). The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

The 9.25% Senior Notes are guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2011 was $806.0 million.

We are obligated to file a registration statement with the SEC to exchange these notes for new freely tradable notes having substantially identical terms within 270 days of the December 17, 2010 issue date and use reasonable efforts to have the registration statement declared effective within that time. Under certain circumstances, we may be required to pay additional cash interest beginning at 0.25% escalating to a maximum of 1% if the registration of the notes does not occur. The registration statement was filed on March 11,2011.

Guarantee of 9.25% Notes Issued by EGC

Our indirect, wholly-owned subsidiary, EGC, is the issuer of the 9.25% Notes which are fully and unconditionally guaranteed by us. We and our subsidiaries, other than EGC, have no significant independent assets or operations. EGC is prohibited from paying dividends to us except that EGC may make a one-time payment to us of up to $25 million for the purpose of paying premiums or other payments associated with the early conversion of our 7.25% preferred stock and EGC may make payments of up to $9 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock.

7.75% Senior Notes

On February 25, 2011, EGC issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the 7.75% Senior Notes). The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

The 7.75% Senior Notes are guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2011 was $249.7 million.

We are obligated to file a registration statement with the SEC to exchange these notes for new freely tradable notes having substantially identical terms within 270 days of the February 25, 2011 issue date and use reasonable efforts to have the registration statement declared effective within that time. Under certain circumstances, we may be required to pay additional cash interest beginning at 0.25% escalating to a maximum of 1% if the registration of the notes does not occur. The registration statement was filed on March 21, 2011.

Guarantee of 7.75% Notes Issued by EGC

Our indirect, wholly-owned subsidiary, EGC, is the issuer of the 7.75% Notes which are fully and unconditionally guaranteed by us. We and our subsidiaries, other than EGC, have no significant independent assets or operations. EGC is prohibited from paying dividends to us except that EGC may make a one-time payment to us of up to $25 million for the purpose of paying premiums or other payments associated with the early conversion of our 7.25% preferred stock and EGC may make payments of up to $9 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock.

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10% Senior Notes

On June 8, 2007, we completed a private offering of $750 million aggregate principal amount of EGC’s 10% Senior Notes due 2013 (the “Old 10% Notes”). On October 16, 2007, we exchanged all of the then issued and outstanding Old 10% Notes for $750 million aggregate principal amount of newly issued 10% Senior Notes due 2013 (the “New Senior Notes”) which had been registered under the Securities Act of 1933, as amended (the “Securities Act”), and contained substantially the same terms as the Old 10% Notes. We did not receive any cash proceeds from the exchange of the Old 10% Notes for the New Senior Notes.

The New 10% Notes are guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We have the right to redeem the New 10% Notes under various circumstances and are required to make an offer to repurchase the New 10% Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the New 10% Notes.

We previously purchased a total of $126.0 million aggregate principal amount of the New 10% Notes at a cost of $90.9 million, plus accrued interest of $3.3 million for a total cost of $94.2 million, reflecting a total gain of $35.1 million pre-tax. As discussed below, on November 12, 2009, we issued $278 million aggregate principal amount of 16% Second Lien Junior Secured Notes due 2014 (“Second Lien Notes”), in exchange for $347.5 million aggregate principal amount of New 10% Notes. In conjunction with the exchange, we contributed $126 million face value of New 10% Notes which we had previously purchased to EGC, who subsequently retired them.

On December 17, 2010, we called $47.6 million face value of the New 10% at 105% of par plus accrued interest. This transaction closed on January 18, 2011. The $2.38 million difference between the call price and the $47.6 million carrying value of the 10% Second Lien notes was charged to loss on retirement of the New 10% notes in the March 31, 2011 quarter.

On February 10, 2011, we offered to purchase for cash (the “Tender Offer”), any and all remaining outstanding New 10% Notes at $1,050 per $1,000 principal amount of New 10% Notes (if tendered on or before February 24, 2011) or at $1,020 per $1,000 principal amount of New 10% Notes if tendered after February 24, 2011 but on or before March 10, 2011. A total of $122.3 million face amount of New 10% Notes were tendered by the February 24, 2011 date and an additional $311,130 face value of New 10% Notes were tendered subsequent to February 24, 2011 but on or before March 10, 2011.

On April 18, 2011, we called the remaining $106.3 million of our New 10% Notes. The call price is 102.5% of par and is expected to close on June 15, 2011.

We believe that the fair value of the $106.3 million of New 10% Notes outstanding as of March 31, 2011 was $110.9 million.

Guarantee of New 10% Notes Issued by EGC

Our indirect, wholly-owned subsidiary, EGC, is the issuer of the New 10% Notes which are fully and unconditionally guaranteed by us. We and our subsidiaries, other than EGC, have no significant independent assets or operations. EGC is prohibited from paying dividends to us except that EGC may make a one-time payment to us of up to $25 million for the purpose of paying premiums or other payments associated with the early conversion of our 7.25% preferred stock and EGC may make payments of up to $9 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock.

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16% Second Lien Notes

On November 12, 2009, the Company issued Second Lien Notes as follows:

·	A total of $278 million of Second Lien Notes were issued in exchange for $347.5 million of New Senior Notes; and

·	A total of $60 million of Second Lien Notes were issued for cash (for each $1.0 million in Second Lien Notes purchased for cash, the purchaser also received 44,082 shares of our common stock).

The Second Lien Notes have a maturity date of June 2014 and are secured by a second lien in our oil and gas properties. In addition, the Second Lien Notes are governed by an inter-creditor agreement between the participants in the revolving credit facility and the Second Lien Notes. Cash interest payable on the Second Lien Notes is 14% with an additional 2% interest payable-in-kind (“Second Lien Note PIK interest”). The Second Lien Note PIK interest is paid through the issuance of additional Second Lien Notes on each interest payment date. These additional Second Lien Notes issued as Second Lien Note PIK interest are identical in terms and conditions to the original Second Lien Notes.

Under the terms of the Second Lien Notes, we were required to exchange the Second Lien Notes for newly issued notes registered under the Securities Act (the “Registered Second Lien Notes”). The Registered Second Lien Notes have identical terms and conditions as the Second Lien Notes. On April 5, 2010, we commenced an offer to exchange the Second Lien Notes for Registered Second Lien Notes. The exchange offer expired on May 3, 2010 and closing was on May 6, 2010. The tendered bonds represented 99.96% of the bonds outstanding.

For accounting purposes, the $278 million aggregate principal amount of Second Lien Notes exchanged for $347.5 million aggregate principal amount of New Senior Notes were recorded at the carrying value of the Registered Second Lien Notes ($347.5 million) and the $69.5 million difference between face value of the Second Lien Notes and carrying value of the New Senior Notes will be amortized as a reduction of interest expense over the life of the New Senior Notes.

For accounting purposes, the $60 million aggregate principal amount of Second Lien Notes for which we received cash were recorded based on the relative fair market values of the Second Lien Notes and the 2.6 million shares of common stock issued using closing price of $10.60 per share of our common stock on November 12, 2009. Based on these relative fair market values, the $60 million aggregate principal amount of Second Lien Notes was recorded at $40.9 million and the common shares were recorded at $19.1 million. The $19.1 million discount between the face value of the $60 million aggregate principal amount of Second Lien Notes and their recorded value will be amortized as an increase in interest expense over the life of the Registered Second Lien Notes.

Refinancing of Existing 16% Second Lien Notes

On November 9, 2010, we called for redemption of $119.7 million aggregate principal amount of our 16% Second Lien Notes at a redemption price of 110% of the principal amount, plus accrued and unpaid interest, pursuant to the terms of the indenture governing the 16% Second Lien Notes. This redemption closed on December 9, 2010. The total payment of $140.9 million included $9.3 million of accrued interest and $12.0 million in redemption premium.

On November 29, 2010, we commenced a tender offer (the “Tender Offer”) for the $222.3 million principal amount of our remaining outstanding 16% Second Lien Notes. In December 2010, a total of $219.9 million face value of 16% Second Lien Notes were tendered. The total payment of $251.0 million included $171,513 of accrued interest and $31.0 million in redemption premium.

On December 17, 2010, we commenced a call of the remaining outstanding 16% Second Lien Notes which closed on January 18, 2011. In December 2010, we escrowed $5.4 million in funds with the trustee of the 16% Second Lien Notes which were sufficient to redeem the remaining outstanding notes.

A total of $42.9 million in redemption premiums were paid related to the call and tender of the 16% Second Lien Notes at December 31, 2010.

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A summary of the loss on the call and tender offers related to our 16% Second Lien Notes and 10% Senior Notes follows (in thousands):

	Three Months Ended March 31, 2011			Nine Months Ended March 31, 2011
16%Second Lien Notes:
Redemption premium paid	$	598		$	43,512
Write-off of unamortized premium		(537	)		(53,134	)
Write-off of unamortized discount		157			14,618
Write-off of unamortized debt issue costs		4			410
Total		222			5,406

10% Senior Notes:
Redemption premium paid		8,493			8,493
Write-off of unamortized debt issue costs		3,484			3,484
Total		11,977			11,977

Total	$	12,199		$	17,383

Put Premium Financing

We finance puts that we purchase with our hedge providers. Substantially all of our hedges are done with members of our bank groups. Put financing is accounted for as debt and this indebtedness is pari pasu with borrowings under the revolving credit facility. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of March 31, 2011 and June 30, 2010, our outstanding hedge financing totaled $4.2 million and $2.3 million, respectively.

Interest Expense

For the three months and nine months ended March 31, 2011 and 2010, interest expense consisted of the following (in thousands):

	Three Months Ended					Nine Months Ended
	March 31,					March 31,
	2011		2010			2011			2010

Revolving credit facility	$	4,243	$	2,432		$	7,140		$	8,541
9.25% Senior Notes due 2017		17,344		—			19,849			—
7.75% Senior Notes due 2019		1,776		—			1,776			—
10% Senior Notes due 2013		4,770		6,818			18,595			33,487
16% Second Lien Notes due 2014		—		13,521			24,967			20,732
Amortization of debt issue cost - Revolving credit facility		2,174		965			4,699			1,869
Amortization of debt issue cost - 10% Senior Notes due 2013		314		589			1,492			1,933
Amortization of debt issue cost - 16% Second Lien Notes due 2014		—		29			54			43
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552		—			644			—
Amortization of debt issue cost – 7.25% Senior Notes due 2017		45		—			45			—
Premium amortization - 16% Second Lien Notes due 2014 (Exchange Offer)		—		1,042			1,894			1,563
Discount amortization - 16% Second Lien Notes due 2014 (Private Placement)		—		(3,791	)		(6,889	)		(5,686	)
Write-off of debt issue costs - Retirement of $126 million in bonds		—		—			—			1,750
Write-off of debt issue costs – Reduction in revolving credit facility		—		—			—			447
Put premium financing and other		200		232			726			2,465
	$	31,418	$	21,837		$	74,992		$	67,144

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Bridge Loan Commitment Fee

In November 2010, we entered into a Bridge Facility Commitment Letter (the “Bridge Commitment”) with a group of banks to provide a $450 million Bridge Facility, if needed, to acquire the ExxonMobil Properties. The Bridge Commitment required the payment of a commitment fee in the amount of 1% of the full amount of the commitments in respect to the Bridge Facility as well as certain other fees in the event we utilized the Bridge Facility to finance the ExxonMobil Acquisition. We did not utilize the Bridge Facility and paid the banks the $4.5 million commitment fee which is included in Other Income (Expense).

Note 7 – Note Payable

In July 2010, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $19.6 million and bears interest at an annual rate of 2.48%. The note amortized over nine months and there is no remaining balance at March 31, 2011.

Note 8 – Asset Retirement Obligations

The following table describes the changes to our asset retirement obligations (in thousands):

Balance at June 30, 2010	$	159,277
Liabilities acquired		204,512
Liabilities incurred		9,137
Liabilities settled		(54,155	)
Accretion expense		22,229
Total balance at March 31, 2011		341,000
Less current portion		30,919
Long-term balance at March 31, 2011	$	310,081

As discussed in Note 4, the asset retirement obligations acquired essentially relate to the ExxonMobil Acquisition and is a provisional estimate.

Note 9 – Derivative Financial Instruments

We enter into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a component of operating income, whereas gains and losses from the settlement of hedging contracts are recorded in crude oil and natural gas revenue.

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX) plus the difference between the purchased put and the sold put strike price.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the three months ended March 31, 2011 resulted in a decrease in crude oil and natural gas sales in the amount of $6.6 million. For the three months ended March 31, 2011, we recognized a gain of approximately $0.2 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and an unrealized gain of approximately $0.4 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

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Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the three months ended March 31, 2010 resulted in an increase in crude oil and natural gas sales in the amount of $9.3 million. For the three months ended March 31, 2010, we recognized a loss of approximately $0.9 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $0.3 million and an unrealized gain of approximately $0.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the nine months ended March 31, 2011 resulted in a loss in crude oil and natural gas sales in the amount of $1.0 million. For the nine months ended March 31, 2011, we recognized a loss of approximately $0.1 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $3.2 million and an unrealized gain of approximately $0.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the nine months ended March 31, 2010 resulted in an increase in crude oil and natural gas sales in the amount of $40.1 million. For the nine months ended March 31, 2010, we recognized a loss of approximately $1.5 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $10.4 million and an unrealized loss of approximately $4.9 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

In March 2009, February 2010, September 2010 and October 2010, we monetized certain hedge positions and received cash proceeds of $66.5 million, $5.0 million, $34.1 million and $8.5 million, respectively. These amounts are carried in stockholders’ equity as part of other comprehensive income and will be recognized in income over the contract life of the underlying hedge contracts. Crude oil and natural gas sales were increased by $9.2 million and $10.4 million for three months ended March 31, 2011 and 2010, respectively, and were increased by $30.0 million and $33.4 million for nine months ended March 31, 2011 and 2010, respectively, related to these monetized hedges and, as a result of the future amortization of these hedges, crude oil and natural gas sales will be increased as follows (in thousands):

Quarter Ended
June 30, 2011	$	9,352
September 30, 2011		8,875
December 31, 2011		7,501
March 31, 2012		1,721
Thereafter		5,973
	$	33,422

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As of March 31, 2011, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) in thousands):

	Crude Oil				Natural Gas
	Volume (MBbls)	Contract Price (1)	Total		Volume (MMMBtus)	Contract Price (1)	Total		Total
Period	Volume (MBbls)	Contract Price (1)	Liability	Fair Value Gain	Volume (MMMBtus)	Contract Price (1)	Asset (Liability)	Fair Value Gain (Loss)	Asset (Liability)	Fair Value Gain (Loss)(2)

Put Spreads
4/11-3/12	1,271	$60.00/$75.00	$(3,781)	$ 5,561					$(3,781)	$5,561
4/12-3/13	853	60.00/75.00	(583)	2,464					(583)	2,464
			(4,364)	8,025					(4,364)	8,025

Puts
4/11-3/12	137	71.67	(15)	298					(15)	298

Swaps
4/11-3/12	3,919	86.24	(84,252)	54,498			$459	$(395)	(83,793)	54,103
4/12-3/13	3,273	89.21	(52,760)	34,294					(52,760)	34,294
4/13-12/13	2,008	94.24	(12,937)	8,409					(12,937)	8,409
			(149,949)	97,201			459	(395)	(149,490)	96,806
Collars
4/11-3/12	2,952	73.85/99.16	(35,835)	23,293	3,660	$4.50/$5.35	280	(183)	(35,555)	23,110
4/12-3/13	3,250	75.82/102.26	(39,011)	25,357	2,750	4.50/5.35	(395)	256	(39,406)	25,613
4/13-12/13	2,920	80.78/106.79	(17,959)	11,673					(17,959)	11,673
			(92,805)	60,323			(115)	73	(92,920)	60,396
Three-Way Collars
4/11-3/12					5,180	3.91/4.94/5.72	1,066	(693)	1,066	(693)
4/12-3/13					7,300	4.10/4.90/5.78	(725)	471	(725)	471
4/13-12/13					7,300	4.10/4.90/5.78	(1,593)	1,035	(1,593)	1,035
							(1,252)	813	(1,252)	813

Total Gain (Loss) on Derivatives			$ (247,133)	$165,847			$(908)	$491	$(248,041)	$166,338

(1) The contract price is weighted-averaged by contract volume.

(2) The gain (loss) on derivative contracts is net of applicable income taxes and includes only those contracts that have been designated as hedges.

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The following table quantifies the fair values, on a gross basis, of all our derivative contracts and identifies its balance sheet location as of March 31, 2011 (in thousands):

	Asset Derivatives		Liability Derivatives
	Balance Sheet Location	Fair Value	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Commodity Contracts	Derivative financial instruments		Derivative financial instruments
	Current	$2,080	Current	$124,665
	Non-current	1,689	Non-current	127,640
		3,769		252,305
Derivatives not designated as hedging instruments
Commodity Contracts	Derivative financial instruments		Derivative financial instruments
	Current	496	Current	1
Total derivatives		$4,265		$252,306

The following table quantifies the fair values, on a gross basis, the effect of derivatives on our financial performance and cash f lows for the nine months ended March 31, 2011 (in thousands):

		Location of (Gain) Loss Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of (Gain) Loss Reclassified from OCI into Income (Effective Portion)	Location of (Gain) Loss Recognized in Income on Derivative (Ineffective Portion)	Amount of (Gain) Loss Reclassified from OCI into Income (Ineffective Portion)
Derivatives in Cash Flow Hedging Relationships	Amount of (Gain) Loss Recognized in Income on Derivative (Effective Portion)



Commodity Contracts	$172,301	Revenue	$966	(Gain) /Loss on derivative financial instruments	$58

Derivatives Not Designated as Hedging Instruments		Amount of (Gain) Loss Recognized in Income on Derivative
	Location of (Gain) Loss Recognized in Income on Derivative



Commodity Contracts	(Gain) loss on derivative financial instruments	$(3,453)

We have reviewed the financial strength of our hedge counterparties and believe the credit risk to be minimal. At March 31, 2011, we had no deposits for collateral with our counterparties.

The following table reconciles the changes in accumulated other comprehensive income (loss) (in thousands):

Accumulated other comprehensive income – June 30, 2010	$	27,706
Hedging activities:
Commodity
Change in fair value loss		(168,973	)
Reclassified to income		(3,329	)
Accumulated other comprehensive loss –March 31, 2011	$	(144,596	)

The amounts expected to be reclassified to income in the next twelve months are $7.2 million income on our commodity hedges.

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Note 10 – Income Taxes

We are a Bermuda company and we are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure.

During the year ended June 30, 2009, we incurred a significant impairment loss related to our oil and gas properties due to the steep decline in global energy prices over that same time period. As a result of this impairment, we were in a position of cumulative reporting losses for the preceding reporting periods. This trend of consecutive quarterly losses has reversed in the last few quarters, but the cumulative loss remains. Additionally, the volatility of energy prices has been problematic and not readily determinable by our management. Under these circumstances, it is management’s opinion that the realization of our tax attributes beyond expected current-year taxable income (including the reversal of existing taxable temporary differences and the resolution of certain hedging activity) does not reach the “more likely than not” criteria under ASC 740 (formerly known as FAS 109). As a result, during the year ended June 30, 2009, we established a valuation allowance of $175.0 million, and have subsequently reduced the valuation allowance due to anticipated pre-tax earnings in the present fiscal year and actual earnings reported in quarters-to-date.

Our Bermuda Companies continue to report a tax provision relating to the accrued U.S. withholding tax required on any interest payments made from the U.S. Companies to the Bermuda Companies. We have accrued a withholding obligation of $7.8 million for the nine months ended March 31, 2011.

We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods. For the nine months ended March 31, 2011, our estimated annual effective tax rate is approximately 12.4%. As discussed above, the significant variance from the U.S. statutory rate is primarily due to the change in the valuation allowance against the U.S. net deferred tax assets and the accrual of the U.S. withholding obligation related to the interest income payable to the Bermuda Companies which may not be offset by other U.S. tax attributes.

Note 11 — Employee Benefit Plans

The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”). We maintain an incentive and retention program for our employees. Participation shares (or “Phantom Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Phantom Stock Units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Phantom Stock Units that have vested, plus the cumulative value of dividends applicable to our common stock.

For fiscal 2010 and 2011, we also awarded performance units. Of the total performance units awarded, 25% are time-based performance units (“Time Based Performance Units”) and 75% are Total Shareholder Return Performance-Based Units (“TSR Performance Based Units”). Both the Time-Based Performance Units and TSR Performance Based Units vest in equal installments on July 21, 2010, 2011 and 2012, for fiscal 2010 grants and July 21, 2011, 2012 and 2013, respectively for 2011 grants.

Time-Based Performance Units. The amount due the employee at the vesting date is equal to the grant date unit value of $5.00 plus the appreciation in the stock price over the performance period, multiplied by the number of units that vest. For the fiscal year 2010 grant, the initial stock price used in determining the change in stock price is $7.40 per share and for the fiscal year 2011 grant the initial stock price is $15.62.

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Performance-Based Performance Units. Performance-Based Performance Units vest at the end of each of three performance periods ending on anniversaries of the grant date (July 21, 2010, 2011 and 2012, respectively, for fiscal year 2010 grants and July 21, 2011, 2012 and 2013, respectively, for 2011 grants) (each, a “Performance Period”). For each Performance-Based Performance Unit, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage change in the price per share of the Company’s common stock from the date on which the Performance-Based Performance Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier, as set forth below.

2010 Grant

·	If Total Shareholder Return is less than 5%, then the TSR Unit Number Modifier is set at 0%.

·	If Total Shareholder Return is greater than or equal to 5% but less than 15%, then the TSR Unit Number Modifier is calculated by multiplying the TSR as a percentage by five and adding 25%.

·	If the Total Shareholder Return performance is greater than or equal to 15% but less than or equal to 30%, then the TSR Unit Number Modifier is calculated by multiplying the TSR as a percentage by six and two-thirds.

·	If the Total Shareholder Return is greater than or equal to 30% for the fiscal year 2010 grant (greater than or equal to 20% for the fiscal year 2011 grant), then the TSR Unit Number Modifier is set at 200%.

2011 Grant

·	If Total Shareholder Return is less than 5%, then the TSR Unit Number Modifier is set at 0%.

·	If Total Shareholder Return is greater than or equal to 5% but less than 10%, then the TSR Unit Number Modifier is calculated by multiplying the TSR as a percentage by ten.

·	If the Total Shareholder Return performance is greater than or equal to 10%, but less than or equal to 20%, then the TSR Unit Number Modifier is calculated by multiplying the TSR as a percentage by ten.

·	If the Total Shareholder Return is greater than or equal to 20%, then the TSR Unit Number Modifier is set at 200%.

For the fiscal year 2010 grant, the initial stock price used in determining the change in stock price is $7.40 per share and for the fiscal year 2011 grant the initial stock price is $15.62.

In addition, the executives may have the opportunity to earn additional compensation based upon the Company’s Total Shareholder Return at the end of the third Performance Period. If upon the end of the third Performance Period, the Total Shareholder Return for the third Performance Period is greater than the Total Shareholder Return of either preceding Performance Period, then the executive will receive a cash payment equal to the difference between (a) what the executive would have received in the initial two Performance Periods had the Total Shareholder Return for each of those Performance Periods been equal to the Total Shareholder Return for the third Performance Period and (b) the aggregate amount that the executive received as payment for the Performance-Based Performance Units during the first two Performance Periods.

At our discretion, at the time the Phantom Stock Units and Performance Based Units vest, employees will settle in either common shares or cash. Upon a change in control of the Company, all outstanding Phantom Stock Units and Performance Based Units become immediately vested and payable.

As of March 31, 2011, we have 1,230,096 unvested Phantom Stock units and 2,454,000 unvested Performance Units. For the three months and nine months ended March 31, 2011 and 2010, we recognized compensation expense of $6.9 million, $4.5 million, $15.5 million and $8.2 million, respectively, related to our Phantom Stock units. For the three months and nine months ended March 31, 2011 and 2010, we recognized compensation expense of $8.6 million, $4.4 million, $22.5 million and $7.4 million, respectively, related to our Performance Units. A liability has been recognized as of March 31, 2011 in the amount of $31.0 million, in accrued liabilities in the accompanying consolidated balance sheet. The amount of the liability will be remeasured at fair value, which is based on period-end stock price, as of each reporting date.

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In order to calculate the fair value of the Performance-Based Performance Units, we have developed a valuation model which best fits their circumstances. We determined that due to the path dependent vesting provisions of the Performance-Based Performance Units, a Monte Carlo approach to simulate the stock price paths was appropriate. Monte Carlo approaches are a class of computational algorithms that rely on repeated random sampling to compute their results. This approach allows us to calculate the value of the Performance-Based Performance Units based on a large number of possible stock price path scenarios. Equity compensation accounting states that any market condition that affects the fair value of an award (including exercisability) must be included in the valuation. Inputs into the valuation model include the underlying stock price at the valuation date, the stipulated stock price at the grant date, the unit value at the grant date, the number of Performance-Based Performance Units awarded, the expected volatility, the expected rate of return and the expected dividend rate.

Restricted Shares activity is as follows:

				Average
				Grant-date
	Number			Fair value
	Of Shares			Per Share
Non-vested at June 30, 2010		81,644		$	24.75
Vested during the nine months ended March 31, 2011		(50,430	)
Non-vested at March 31, 2011		31,214		$	24.75

We determine the fair value of the Restricted Shares based on the market price of our Common Stock on the date of grant. Compensation cost for the Restricted Shares is recognized on a straight line basis over the requisite service period. For the three months and nine months ended March 31, 2011 and 2010, we recognized compensation expense of $0.2 million, $0.4 million, $0.8 million and $1.2 million, respectively, related to our Restricted Shares. As of March 31, 2011, there was approximately $240,000 of unrecognized compensation cost related to non-vested Restricted Shares. We expect approximately $193,000 to be recognized over fiscal 2011 and $47,000 to be recognized during the fiscal year ended 2012.

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or that have been newly issued by us. During the nine months ended March 31, 2011 and 2010, we issued 281,354 shares and 217,746 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the period. The current period is from January 1, 2011 to June 30, 2011. For the three months and nine months ended March 31, 2011 and 2010, we had charged $189,000, $162,000, $378,000 and $255,000, respectively, to compensation expense related to this plan. The plan has a limit of 1,000,000 common shares. During the nine months ended March 31, 2011 and 2010, we issued 89,260 shares and 163,682 shares, respectively, under the Employee Stock Purchase Plan.

In September 2008, our Board of Directors granted 300,000 stock options to certain officers. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vest over a three year period and may be exercised any time prior to September 10, 2018. As of March 31, 2011, 100,000 of the stock options remain unvested and will vest on September 10, 2011. As of March 31, 2011, 100,000 of the vested options have been exercised.

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A summary of our stock option activity and related information is as follows:

	Nine Months Ended March 31,
	2011			2010
	Shares		Weighted Ave.	Shares	Weighted Ave.
	Under		Exercise	Under	Exercise
	Option		Price	Option	Price

Beginning balance		240,000	$17.50	300,000	$17.50
Vested		(140,000)		(60,000)
Ending balance		100,000	$17.50	240,000	$17.50

For the three months and nine months ended March 31, 2011 and 2010, we recognized compensation expense of $88,000, $200,000, $129,000 and $800,000, respectively, related to stock options. As of March 31, 2011, there was $146,000 of unrecognized compensation expense related to non-vested stock option grants. We expect approximately $88,000 to be recognized during the fiscal year ended 2011 and approximately $58,000 to be recognized during the fiscal year ended 2012.

We utilize the Black-Scholes model to determine fair value, which incorporates assumptions to value stock-based awards. The dividend yield on our common stock was based on actual dividends paid at the time of the grant. The expected volatility is based on historical volatility of our common stock. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant.

Defined Contribution Plans. Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401 (k) Plan that provides for matching. The cost to us under these plans for the three months ended March 31, 2011 and 2010 was $0.7 million for profit sharing and $0.4 million for the 401 (k) Plan and $0.5 million for profit sharing and $0.6 million for the 401 (k) Plan, respectively. The cost to us under these plans for the nine months ended March 31, 2011 and 2010 was $1.9 million for profit sharing and $1.5 million for the 401 (k) Plan and $2.4 million for profit sharing and $1.2 million for the 401 (k) Plan, respectively.

Note 12 – Stockholders’ Equity

Common Stock

At our 2009 Annual General Meeting, our shareholders approved a share consolidation or reverse stock split at certain pre-determined ratios at any time prior to December 31, 2010, subject to the approval of our board of directors. In January 2010, our board of directors approved a 1:5 stock consolidation or reverse stock split effective January 29, 2010. The shareholders also voted to increase our authorized capital from 80,000,000 common shares, par value $.005 per share to 200,000,000 common shares by creating 120,000,000 new common shares. The reverse stock split has been retroactively applied to all periods presented.

Our common stock trades on The NASDAQ Capital Market (the “NASDAQ”) and on the London Stock Exchange AIM under the symbol “EXXI.” Our restricted common stock trades on the AIM under the symbol “EXXS.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders.

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December 2009 Equity Offering

On December 14, 2009, we closed on an offering of 18,000,000 shares of $0.005 par value common stock at a price of $9.50 per share, less $0.50 per share underwriters’ commission. On December 28, 2009, the underwriters exercised their over-allotment option acquiring an additional 821,046 shares at $9.50 per share, less $0.50 per share in underwriters’ commissions. We received net proceeds of $188.0 million for the combined common stock offerings, after deducting $0.50 per share underwriters’ commissions and offering costs.

Conversion of 7.25% Preferred Stock

In October and November 2010, in five separate private transactions, we issued a total of 4,569,107 shares of our $.005 par value common stock in exchange for 482,930 shares of our 7.25% Preferred Stock. A total of 4,236,223 of these common shares were issued for the stated conversion price of 8.77192 common shares per share of 7.25% Preferred Stock, 11,033 common shares were issued for accrued and unpaid dividends from September 15, 2010 on the 7.25% Preferred Stock and 321,851 common shares were issued as an inducement for the early conversion of the 7.25% Preferred Stock. In addition to the common stock issued, a cash payment of $1.3 million was made to induce the conversions. The total amounts paid in cash and stock related to these five transactions to induce conversion of preferred stock were $9.0 million.

On October 21, 2010, we launched an exchange offer for shares of our 7.25% Preferred Stock outstanding. The exchange offer provided for the issuance of 8.77192 shares of our unrestricted common stock per share of 7.25% Preferred Stock and a cash payment to induce the conversion. The exchange offer closed on November 19, 2010. A total of 517,970 shares of 7.25% Preferred Stock were exchanged for 4,543,583 shares of common stock and a cash payment of $10.5 million, which included accrued dividends of $0.7 million, was paid at the closing date as an inducement for conversion.

During the three months ended March 31, 2011, we issued 22,808 shares of our common stock in exchange for 2,600 shares of our 7.25% Preferred Stock. In addition, we paid a total of $35,343 in cash to induce the conversions.

During the three months and nine months ended March 31, 2011, we have recognized $19.8 million as a reduction of equity and income available to common stockholders related to the induced conversion of 7.25% Preferred Stock. Other expenses related to the inducement are included in general and administrative expenses.

At March 31, 2011 we have 96,500 shares of 7.25% Preferred Stock outstanding.

November 2010 Equity Offerings

On November 3, 2010, we closed on concurrent offerings of common and preferred stock. We sold 12 million shares of our unrestricted common stock at $20.75 per share less $0.985 per share in underwriting commissions. Net proceeds from the common stock offering were approximately $237.2 million, after deducting underwriting commissions, but before other offering expenses. We also sold 1.15 million shares of 5.625% perpetual preferred stock at $250 per share less $3.75 per share (1.5%) in underwriting commissions. Net proceeds from the sale of preferred stock were approximately $283.2 million, after deducting underwriting commissions, but before other offering expenses.

On November 5, 2010, the underwriters exercised their over-allotment on the common stock offering resulting in the issuance of an additional 1.8 million common shares. Net proceeds from the sale of the 1.8 million shares of common stock were approximately $35.6 million, after deducting underwriting commissions, but before other offering expenses.

Preferred Stock

Our bye-laws authorize the issuance of 2,500,000 shares of preferred stock. Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance. At March 31, 2011, we have 1.15 million shares of 5.625% Preferred Stock outstanding and 96,500 shares of 7.25% Preferred Stock outstanding or a total of 1,246,500 preferred shares issued. Therefore, we have 1,253,500 shares of preferred stock authorized but not issued at March 31, 2011.

On December 14, 2009, the Company sold 1,100,000 shares of 7.25% cumulative perpetual preferred stock (our “7.25% Preferred Stock”) at a $100 per share. Net proceeds to the Company after deducting the 3% underwriters’ commission were $106.6 million.

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Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock are payable quarterly in arrears on each March 15, June 15, September 15 and December 15 of each year.

Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, shares of the Company’s common stock, or a combination thereof. If the Company elects to make payment in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of the Company’s common stock as determined on the second trading day immediately prior to the record date for such dividend.

The 7.25% Preferred Stock is convertible into 8.77192 shares of the Company’s common stock or approximately $11.40 per share. On or after December 15, 2014, the Company may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 150% of the then-prevailing conversion price (currently $17.10).

The 5.625% Preferred Stock is convertible into 9.8353 shares of the Company’s common stock or approximately $25.42 per share. On or after December 15, 2013, the Company may cause the 5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price (currently $33.05).

Unit Purchase Option

As part of the placement on the AIM in October 2005, we issued to an underwriter and its designees (including its officers) an option (exercisable in whole or part) to subscribe up to 1,000,000 Units at a price of $33.00 per Unit. Each unit would consist of one common share and two warrants. The warrants were each convertible into a share of our common stock at $25.00 per share and expired on October 20, 2009. Fair value of the options, determined by using the Black-Scholes pricing model, was approximately $8.2 million, and recorded as a cost of the placement in stockholders’ equity and additional paid-in capital. The common stock portion of the Units expired on October 20, 2010. There were no unit purchase options exercised prior to their expiration.

Note 13 — Earnings per Share

Basic earnings per share of common stock is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of restricted stock and stock options and the potential dilution that would occur if preferred stock was converted to common stock. The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2011		2010		2011		2010

Net Income	$	18,371	$	11,088	$	29,438	$	15,234
Preferred Stock Dividends		4,278		1,994		8,698		2,326
Induced Conversion of Preferred Stock		44		—		19,840		—
Net Income Attributable to Common Stockholders	$	14,049	$	9,094	$	900	$	12,908

Weighted average shares outstanding for basic EPS		74,221		50,713		63,490		37,790
Add dilutive securities		200		10,017		242		336
Weighted average shares outstanding for diluted EPS		74,421		60,730		63,732		38,126

Net Income Per Share Attributable to Common Stockholders
Basic	$	0.19	$	0.18	$	0.01	$	0.34
Diluted	$	0.19	$	0.18	$	0.01	$	0.34

For the three months and nine months ended March 31, 2011, 12,178,031 and 11,227,616 common stock equivalents, respectively, were excluded from the diluted average shares due to an anti-dilutive effect. For the three months and nine months ended March 31, 2010, zero and 3,732,862 common stock equivalents, respectively, were excluded from the diluted average shares due to an anti-dilutive effect.

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Note 14 — Commitments and Contingencies

Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material affect on our financial position or results of operations.

Lease Commitments. We have a non-cancelable operating lease for office space that expires on December 31, 2017. Future minimum lease commitments as of March 31, 2011 under the operating leases are as follows (in thousands):

Twelve Months Ending March 31,

2012	$	1,423
2013		1,435
2014		1,333
2015		1,267
2016		1,313
Thereafter		2,356
Total	$	9,127

Rent expense for the three months and nine months ended March 31, 2011 and 2010 was approximately $512,000, $550,000, $1,457,000 and $1,686,000, respectively.

Letters of Credit and Performance Bonds. We had $231.5 million in letters of credit and $26.6 million of performance bonds outstanding as of March 31, 2011.

Drilling Rig Commitments. We entered into a drilling rig commitment for two wells on March 14, 2011 at $110,000 per day until well completion. The commitment extends past March 31, 2011, thus, the commitment amount cannot be calculated since the well completion date is not known.

Note 15 — Fair Value of Financial Instruments

We use various methods to determine the fair values of our financial instruments and other derivatives which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For our natural gas and oil derivatives, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments. Our natural gas and oil derivatives are classified as described below:

•

Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets). Included in this level are our natural gas and oil derivatives whose fair values are based on commodity pricing data obtained from independent pricing sources.

The fair value of our financial instruments at March 31, 2011 was as follow (in thousands):

	Level 2
Assets:
Natural Gas and Oil Derivatives	$	3,920

Liabilities:
Natural Gas and Oil Derivatives	$	251,961

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Note 16 — Prepaid Expenses and Other Current Assets and Accrued Liabilities

Prepaid expenses and other current assets and accrued liabilities consist of the following (in thousands):

	March 31, 2011		June 30, 2010

Prepaid expenses and other current assets
Advances to joint interest partners	$	8,887	$	22,055
Insurance		8,109		1,635
Inventory		6,177		4,805
Royalty deposit		1,959		2,341
Other		908		3,643
Total prepaid expenses and other current assets	$	26,040	$	34,479

Accrued liabilities
Advances from joint interest partners	$	262	$	3,659
Employee benefits and payroll		30,525		27,014
Interest		24,788		3,855
Accrued hedge payable		18,163		9,407
Undistributed oil and gas proceeds		23,353		20,266
Other		4,257		4,582
Total accrued liabilities	$	101,348	$	68,783

Note 17 – Supplemental Cash Flow Information

The following represents our supplemental cash flow information (in thousands):

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2011		2010		2011		2010

Cash paid for interest	$	7,662	$	3,029	$	49,938	$	44,492

The following represents our non-cash investing and financing activities (in thousands):

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2011			2010			2011			2010

Additions to property and equipment by recognizing asset retirement obligations	$	6,483		$	62,232		$	213,650		$	63,915
Financing of insurance premiums		(6,574	)		(6,549	)		—			—
Conversion of preferred stock to common stock		—			—			(7,884	)		—
Preferred stock dividends		(1,875	)		—			371			332

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ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

·	our business strategy;

·	our financial position;

·	the extent to which we are leveraged;

·	our cash flow and liquidity;

·	declines in the prices we receive for our oil and gas affecting our operating results and cash flows;

·	economic slowdowns that can adversely affect consumption of oil and gas by businesses and consumers;

·	uncertainties in estimating our oil and gas reserves;

·	replacing our oil and gas reserves;

·	uncertainties in exploring for and producing oil and gas;

·	our inability to obtain additional financing necessary in order to fund our operations, capital expenditures, and to meet our other obligations;

·	availability of drilling and production equipment and field service providers;

·	disruption of operations and damages due to hurricanes or tropical storms;

·	availability, cost and adequacy of insurance coverage;

·	competition in the oil and gas industry;

·	our inability to retain and attract key personnel;

·	the effects of government regulation and permitting and other legal requirements; and

·	costs associated with perfecting title for mineral rights in some of our properties.

Other factors that could cause our actual results to differ from our projected results are described in (1) Part II, “Item 1A. Risk Factors” and elsewhere in this report, (2) our Annual Report on Form 10-K for the fiscal year ended June 30, 2010, (3) our reports and registration statements filed from time to time with the SEC and (4) other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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Overview

We are an independent oil and natural gas exploration and production company with properties focused in the U.S. Gulf Coast and the Gulf of Mexico. Our business strategy includes: (i) acquiring oil and gas properties; (ii) exploiting our core assets to enhance production and ultimate recover of reserves; and (iii) utilizing a small portion of our capital program to explore the ultra-deep shelf for large potential quantities of oil and gas. Our operations are geographically focused and we target acquisitions of oil and gas properties with which we can add value by increasing production and ultimate recovery of reserves, whether through exploitation or exploration, often using reprocessed seismic data to identify previously overlooked opportunities.

At March 31, 2010, we operated or had an interest in 447 producing wells on 130,853 net developed acres, including interests in 60 producing fields. All of our properties are located on the Gulf Coast and in the Gulf of Mexico, with approximately 90% of our proved reserves being offshore. This concentration facilitates our ability to manage the operated fields efficiently and our high number of wellbore locations provides diversification of our production and reserves. We believe operating our assets is key to our strategy; approximately 86% of our proved reserves are on properties operated by us. We have a seismic database covering approximately 3,900 square miles, primarily focused on our existing operations. This database has helped us identify at least 100 development and exploration opportunities. We believe the mature legacy fields on our acquired properties will lend themselves well to our aggressive exploitation strategy and expect to identify incremental exploration opportunities on the properties.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. As evidenced by our successful amendment of our revolving credit facility and the recent successful equity and debt offerings by us and our peers, we believe that we continue to have adequate access to capital and we have been successful at improving our financial position to date.

Although we currently expect to fund our capital program from existing cash flow from operations, these cash flows are dependent upon future production volumes and commodity prices. Maintaining adequate liquidity may involve the issuance of debt and equity at less attractive terms, could involve the sale of non-core assets and could require reductions in our capital spending. In the near-term we will focus on maximizing returns on existing assets by managing our costs and selectively deploying capital to improve existing production and pursuing our ultra-deep shelf exploration program.

Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. As required by our revolving credit facility, we have mitigated this volatility by implementing a hedging program on a portion of our total anticipated production. See Note 9 of Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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We face the challenge of natural gas and oil production declines. As a given well’s initial reservoir pressures are depleted, natural gas and oil production decreases, thus reducing our total reserves. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues. In accordance with our business strategy, we intend to invest the capital necessary to maintain our production at existing levels over the long-term provided that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue our debt and equity securities on favorable terms, or at all, and we may be unable to refinance our revolving credit facility when it expires. Additionally, should commodity prices significantly decline, our borrowing base under our revolving credit facility may be re-determined such that it will not provide for the working capital necessary to fund our capital spending program.

Highlights

Ultra-Deep Shelf Exploration and Development Activity

We participate in a joint venture (the “Partnership”) led by McMoRan Exploration Company with respect to several prospects in the ultra-deep shelf in the Gulf of Mexico. Data received to date from ultra-deep shelf drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld (i.e. listric fault) in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, the Partnership has identified 15 ultra-deep shelf prospects in shallow water near existing infrastructure. The Partnership’s ultra-deep shelf drilling plans in calendar year 2010 included the Blackbeard East and Lafitte exploratory wells and delineation drilling at Davy Jones. Future plans also include the John Paul Jones prospect located north of Davy Jones.

In February 2010, the Davy Jones discovery well on South Marsh Island Block 230 was drilled to a total depth of 29,000 feet. As reported in January 2010, the Partnership logged 200 net feet of pay in multiple Eocene/Paleocene (Wilcox) sands in the well. In March 2010, a production liner was set and the well was temporarily abandoned until necessary equipment for the completion is available. The Partnership, working with a team of experts, has initiated studies on the design for the completion of the well. Flow testing is expected to confirm the ultimate hydrocarbon flow rates from the well. Various fast-track alternatives to flow test the well are being evaluated. Timing of the flow test and completion is uncertain and subject to a number of factors.

On April 7, 2010, the Partnership commenced drilling the Davy Jones offset appraisal well (“Davy Jones #2”) on South Marsh Island Block 234, two and a half miles southwest of the discovery well. The well is currently drilling below 27,900 feet towards a proposed total depth of 29,950 feet. Davy Jones #2 is expected to test similar sections up-dip to the discovery well, as well as deeper objectives, including potential additional Wilcox and possibly Cretaceous (“Tuscaloosa”) sections.

Davy Jones involves a large ultra-deep shelf structure encompassing four lease blocks (20,000 acres). We are funding 14.1 percent of the exploratory costs to earn a 15.8 percent working interest and 12.6 percent net revenue interest in Davy Jones. As of March 31, 2011, our investment in both wells at Davy Jones totaled $44.1 million.

The Blackbeard East ultra-deep shelf exploration well commenced drilling on March 8, 2010 and is drilling below 32,600 feet. The well, which is located in 80 feet of water on South Timbalier Block144, has a proposed total depth of 34,000 feet, targeting Middle and Deep Miocene objectives seen below 30,000 feet in Blackbeard West, nine miles away. We are funding 16 percent of the exploratory costs to earn an 18 percent working interest and 14.35 percent net revenue interest in Blackbeard East. As of March 31, 2011, our investment in the well totaled $27.5 million.

The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is drilling below 17,900 feet and has a proposed total depth of 29,950 feet. Like Blackbeard East, Lafitte will target Middle and Deep Miocene objectives. Lafitte is located on Eugene Island Block 223 in 140 feet of water. As of March 31, 2011, our investment in the well totaled $12.1 million.

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Information gained from the Blackbeard East and Lafitte wells will enable the partnership to consider priorities for future operations at Blackbeard West. As previously reported, the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation, and the well was temporarily abandoned. The Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE,” formerly the Minerals Management Service) of the U.S. Department of the Interior has granted a geophysical Suspension of Operations (“SOO”) to extend the terms of Blackbeard West leases. The SOO is allowing the partnership to evaluate whether to drill deeper at Blackbeard West, drill an offset location or complete the well to test the existing zones. Our investment in the Blackbeard West well totaled $27.1 million at March 31, 2011.

We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep shelf exploration and development activity.

ExxonMobil Acquisition

On December 17, 2010, we closed on the purchase of certain shallow-water Gulf of Mexico shelf oil and natural gas interests from ExxonMobil for $1.01 billion in cash, subject to adjustment. The ExxonMobil Properties:

•had estimated proved reserves as of November 30, 2010 of 49.5 MMBOE, of which 61% were oil and 68% were proved developed;

•are located in water depths of 470 feet or less;

•include 160 producing wells in nine fields;

•had average daily production of approximately 16.2 MBOED as for the three months ended March 31, 2011; and

•include approximately 180 miles of gathering lines as well as seismic data and field studies related to the properties.

The ExxonMobil Acquisition provides an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus on oil-weighted assets in our core area of expertise, the shallow waters of the Gulf of Mexico. The ExxonMobil Acquisition also provides us access to infrastructure and extensive acreage, complemented by seismic data and field studies. We intend to pursue our strategy of acquiring, exploiting and exploring the ExxonMobil Properties, which provide a portfolio of drilling and recompletion opportunities that we can pursue while we analyze the potential for higher-impact exploration prospects. We operate approximately 94% of the ExxonMobil properties. We are currently the third largest oil producer on the Gulf of Mexico shelf, with interests in seven of the top 11 fields on the shelf.

The core properties we acquired in the ExxonMobil Acquisition are:

·	South Timbalier 54 Field. We own a 100% working interest in the South Timbalier 54 field, which had net production for the quarter ended March 31, 2011 of 4.0 MBOED. Net proved reserves for the field were estimated to be 59% oil at November 30, 2010.

·	West Delta 30. We own approximately 75% working interest in the West Delta 30 field, which had net production for the quarter ended March 31, 2011 of 3.9 MBOED. Net proved reserves for the field were estimated to be 64% oil at November 30, 2010.

·	West Delta 73. We own a 100% working interest in the West Delta 73 field, which had net production for the quarter ended March 31, 2011 of 2.1 MBOED. Net proved reserves for the field were estimated to be 71% oil at November 30, 2010.

·	Grand Isle 43. We own a 100% working interest in the West Delta Blocks 72 and 93 of Grand Isle 43 field, which had net production for the quarter ended March 31, 2011 of 2.1 MBOED. Net proved reserves for the field were estimated to be 34% oil at November 30, 2010.

·	Grand Isle 16/18. We own a 100% working interest in the Grand Isle 16/18 field, which had net production for the quarter ended quarter ended March 31, 2011 of 2.3 MBOED. Net proved reserves for the field were estimated to be 70% oil at November 30, 2010.

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Mit Acquisition

On December 22, 2009, we closed on the acquisition of certain Gulf of Mexico shelf oil and natural gas interests from MitEnergy Upstream LLC, a subsidiary of Mitsui & Co., Ltd. (the “Mit Acquisition”), for cash consideration of $276.2 million. For accounting purposes, we recorded this acquisition as effective November 20, 2009, the date that we gained control of the assets acquired and liabilities assumed. This acquisition was funded with cash on hand and net proceeds from the offering of 18,821,046 shares of our common stock and 1,100,000 shares of our 7.25% cumulative perpetual preferred stock (our 7.25% Preferred Stock”) completed on December 12, 2009.

The Mit Acquisition involves mirror-image non-operated interests in the same group of properties we purchased from Pogo Producing Company in June 2007. These properties included 30 fields of which production was approximately 77% crude oil and 80% of which were already operated by us. Offshore leases included in this acquisition totaled nearly 33,000 net acres.

Known Trends and Uncertainties

BP/Deepwater Horizon Oil Spill. The recent explosion and sinking of the Deepwater Horizon drilling rig and resulting oil spill has created uncertainties about the impact on our future operations in the Gulf of Mexico (see “Item 1A. Risk Factors”). Increased regulation in a number of areas could disrupt, delay or prohibit future drilling programs and ultimately impact the fair value of our unevaluated properties. As of March 31, 2011, we have approximately $447 million of investments in unevaluated oil and gas properties that relate to offshore leases. If the fair value of these investments were to fall below the recorded amounts, the excess would be transferred to evaluated oil and gas properties thereby affecting the computation of amounts for depreciation, depletion and amortization and potentially our ceiling test computation. As of March 31, 2011, the computation of our ceiling test indicated a cushion of approximately $563 million.

Hurricanes. Since the majority of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes is becoming more difficult to obtain. We have narrowed our insurance coverage to selected properties, increased our deductibles and are shouldering more hurricane related risk in the environment of rising insurance rates. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

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Operational Information (In thousands except for unit amounts)

	Quarter Ended
	Mar. 31, 2011			Dec. 31, 2010			Sept. 30, 2010			June 30, 2010			Mar. 31, 2010
	Mar. 31, 2011			Dec. 31, 2010			Sept. 30, 2010			June 30, 2010			Mar. 31, 2010
Operating revenues
Crude oil sales	$	233,081		$	156,273		$	118,263		$	113,908		$	117,932
Natural gas sales		32,193			18,301			19,446			19,945			22,872
Hedge gain (loss)		(6,638	)		(621	)		6,291			5,538			9,323
Total revenues		258,636			173,953			144,000			139,391			150,127
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		87.9	%		89.5	%		85.9	%		85.1	%		83.8	%
Including hedge gain (loss)		83.8	%		84.2	%		80.4	%		78.6	%		76.0	%
Operating expenses
Lease operating expense
Insurance expense		7,278			6,498			6,143			7,220			6,602
Workover and maintenance		4,317			4,105			7,618			5,269			8,452
Direct lease operating expense		58,471			34,644			30,413			28,816			25,778
Total lease operating expense		70,066			45,247			44,174			41,305			40,832
Production taxes		721			716			694			1,065			870
DD&A		91,301			62,922			54,077			50,556			50,761
General and administrative		23,155			15,786			18,597			13,127			14,452
Other – net		9,288			4,710			4,836			5,116			6,649
Total operating expenses		194,531			129,381			122,378			111,169			113,564
Operating income	$	64,105		$	44,572		$	21,622		$	28,222		$	35,563

Sales volumes per day
Natural gas (MMcf)		84.6			53.7			48.1			48.2			48.4
Crude oil (MBbls)		27.3			20.4			17.9			17.3			17.3
Total (MBOE)		41.4			29.4			25.9			25.3			25.4
Percent of sales volumes from crude oil		65.9	%		69.5	%		69.1	%		68.3	%		68.3	%

Average sales price
Natural gas per Mcf	$	4.23		$	3.70		$	4.39		$	4.55		$	5.25
Hedge gain per Mcf		1.28			1.85			1.97			2.27			3.03
Total natural gas per Mcf	$	5.51		$	5.55		$	6.36		$	6.82		$	8.28

Crude oil per Bbl	$	94.94		$	83.14		$	71.79		$	72.42		$	75.54
Hedge loss per Bbl		(6.67	)		(5.18	)		(1.48	)		(2.80	)		(2.46	)
Total crude oil per Bbl	$	88.27		$	77.96		$	70.31		$	69.62		$	73.08

Total hedge gain (loss) per BOE	$	(1.78	)	$	(0.23	)	$	2.64		$	2.40		$	4.08

Operating revenues per BOE	$	69.46		$	64.34		$	60.37		$	60.50		$	65.65
Operating expenses per BOE
Lease operating expense
Insurance expense		1.95			2.40			2.58			3.13			2.89
Workover and maintenance		1.16			1.52			3.19			2.29			3.70
Direct lease operating expense		15.70			12.81			12.75			12.51			11.27
Total lease operating expense		18.81			16.73			18.52			17.93			17.86
Production taxes		0.19			0.26			0.29			0.46			0.38
DD&A		24.52			23.27			22.67			21.94			22.20
General and administrative		6.22			5.84			7.80			5.70			6.32
Other – net		2.49			1.74			2.02			2.22			2.91
Total operating expenses		52.23			47.84			51.30			48.25			49.67
Operating income per BOE	$	17.23		$	16.50		$	9.07		$	12.25		$	15.98

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Results of Operations

Three Months Ended March 31, 201 Compared With the Three Months Ended March 31, 2010.

Our consolidated income available for common stockholders for the three months ended March 31, 2011 was $14.0 million or $0.19 diluted income per common share (“per share”) as compared to consolidated net income available for common stockholders of $9.1 million or $0.18 diluted income per share for the three months ended March 31, 2010. The increase is primarily due to higher production volumes and higher overall commodity prices in the current fiscal year quarter partially offset by higher production expenses coupled with the induced conversion costs of the preferred stock.

Price and Volume Variances

	Three Months Ended									Percent			Revenue
	March 31,						Increase			Increase			Increase
	2011			2010			(Decrease)			(Decrease)			(Decrease)
													(In thousands)
Price Variance (1)
Crude oil sales prices (per Bbl)	$	88.27		$	73.08		$	15.19			20.8	%	$	37,291
Natural gas sales prices (per Mcf)		5.51			8.28			(2.77	)		(33.5	)%		(21,082	)
Total price variance														16,209

Volume Variance
Crude oil sales volumes (MBbls)		2,455			1,561			894			57.3	%		65,325
Natural gas sales volumes (MMcf)		7,611			4,354			3,257			74.8	%		26,975
BOE sales volumes (MBOE)		3,724			2,287			1,437			62.8	%
Percent of BOE from crude oil		65.9	%		68.3	%
Total volume variance														92,300

Total price and volume variance													$	108,509

(1) Commodity prices include the impact of hedging activities.

Revenue Variances

	Three Months Ended March 31,
	2011		2010		Increase		Percent Increase
	(In Thousands)

Crude oil	$	216,711	$	114,095	$	102,616		89.9	%
Natural gas		41,925		36,032		5,893		16.4	%
Total revenues	$	258,636	$	150,127		108,509		72.3	%

Revenues

Our consolidated revenues increased $108.5 million in the third quarter of fiscal 2011 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher crude oil and natural gas sales volumes as a result of the ExxonMobil Acquisition. Revenue variances related to commodity prices and sales volumes are described below.

Price Variances

Commodity prices are one of our key drivers of earnings generation and net operating cash flow. Higher overall commodity prices increased revenues by $16.2 million in the third quarter of fiscal 2011. Average natural gas prices, including a $1.28 realized gain per Mcf related to hedging activities, decreased $2.77 per Mcf during the third quarter of fiscal 2011, resulting in decreased revenues of $21.1 million. Average crude oil prices, including a $6.67 realized loss per barrel related to hedging activities, increased $15.19 per barrel in the third quarter of fiscal 2011, resulting in increased revenues of $37.3 million. Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during the third quarter of fiscal 2011 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash from operating activities, potentially causing us to expend less on our capital program. Lower spending on our capital program could result in a reduction of the amount of production volumes we are able to produce. We cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

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Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Higher total sales volumes in the third quarter of fiscal 2011 resulted in increased revenues of $92.3 million. Crude oil sales volumes increased 10.0 MBbls per day in the third quarter of fiscal 2011, resulting in increased revenues of $65.3 million. Natural gas sales volumes increased 36.2 MMcf per day in the third quarter of fiscal 2011, resulting in increased revenues of $27.0 million. The increase in crude oil and natural gas sales volumes in the third quarter of fiscal 2011 was primarily due to the ExxonMobil Acquisitions coupled with the success of our drilling program.

As mentioned above, depressed commodity prices over an extended period of time or other unforeseen events could occur that would result in our being unable to sustain a capital program that allows us to meet our production growth goals. However, we cannot predict whether such events will occur.

Below is a discussion of Costs and Expenses and Other (Income) Expense.

Costs and Expenses and Other (Income) Expense

	Three Months Ended March 31,
	2011						2010
	Amount			Per BOE			Amount			Per BOE			Increase (Decrease) Amount
Costs and expenses	(In Thousands, except per unit amounts)
Lease operating expense
Insurance expense	$	7,278		$	1.95		$	6,602		$	2.89		$	676
Workover and maintenance		4,317			1.16			8,452			3.70			(4,135	)
Direct lease operating expense		58,471			15.70			25,778			11.27			32,693
Total lease operating expense		70,066			18.81			40,832			17.86			29,234
Production taxes		721			0.19			870			0.38			(149	)
DD&A		91,301			24.52			50,761			22.20			40,540
Accretion of asset retirement obligations		9,907			2.66			6,335			2.77			3,572
General and administrative expense		23,155			6.22			14,452			6.32			8,703
Loss (gain) on derivative financial instruments		(619	)		(0.17	)		314			0.14			(933	)
Total costs and expenses	$	194,531		$	52.23		$	113,564		$	49.67		$	80,967

Other (income) expense
Other (income) expense - other	$	12,184		$	3.27		$	(13	)	$	(0.01	)	$	12,197
Interest expense		31,418			8.44			21,837			9.55			9,581
Total other (income) expense	$	43,602		$	11.71		$	21,824		$	9.54		$	21,778

Costs and expenses increased $81.0 million in the third quarter of fiscal 2011. This increase in costs and expenses was due in part to the ExxonMobil Acquisition which increased production related expenses in the third quarter of fiscal 2011.

DD&A expense increased $40.5 million. This increase is principally due to increased production ($31.9 million) and a higher DD&A rate ($8.6 million). Lease operating expense increased $29.2 million in the third quarter of fiscal 2011 compared to the third quarter of fiscal 2010. This increase is primarily due to higher direct lease operating expense as a result of the ExxonMobil Acquisition partially offset by lower workover and maintenance costs in the third quarter of fiscal 2011. The third quarter of fiscal 2010 had higher platform maintenance.

General and administrative expense increased $8.7 million in the third quarter of fiscal 2011 principally as a result of the higher compensation expense related to Phantom and Performance Units due to our rising common stock price.

Other (income) expense increased $21.8 million in the third quarter of fiscal 2011. This increase was primarily due to the items discussed below.

Other expense increased $12.2 million due principally to the loss on the redemption of the 16% Second Lien Notes. Interest expense increased $9.6 million due to the increase in borrowings. On a per unit of production basis, interest expense decreased 11.6%, from $9.55/BOE to $8.44/BOE.

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Income Tax Expense

Income tax expense decreased $1.5 million in the third quarter of fiscal 2011 compared to the third quarter of fiscal 2010. The effective income tax rate for the third quarter of fiscal 2011 decreased from the third quarter of fiscal 2010 from 24.8% to 10.4%.

Nine Months Ended March 31, 2011 Compared With the Nine Months Ended March 31, 2010.

Our consolidated income available for common stockholders for the nine months ended March 31, 2011 was $0.9 million or $0.01 diluted income per common share (“per share”) as compared to consolidated net income available for common stockholders of $12.9 million or $0.34 diluted income per share for the nine months ended March 31, 2010. The decrease is primarily due to higher other expense coupled with the induced conversion costs of the preferred stock partially offset by higher production volumes net of related costs in the current fiscal year.

Price and Volume Variances

	Nine Months Ended									Percent			Revenue
	March 31,						Increase			Increase			Increase
	2011			2010			(Decrease)			(Decrease)			(Decrease)
													(In thousands)
Price Variance (1)
Crude oil sales prices (per Bbl)	$	80.09		$	73.67		$	6.42			8.7	%	$	38,404
Natural gas sales prices (per Mcf)		5.74			7.28			(1.54	)		(21.2	)%		(26,154	)
Total price variance														12,250

Volume Variance
Crude oil sales volumes (MBbls)		5,982			3,780			2,202			58.3	%		162,238
Natural gas sales volumes (MMcf)		16,983			11,149			5,834			52.3	%		42,561
BOE sales volumes (MBOE)		8,812			5,638			3,174			56.3	%
Percent of BOE from crude oil		67.9	%		67.0	%
Total volume variance														204,799

Total price and volume variance													$	217,049

(1) Commodity prices include the impact of hedging activities.

Revenue Variances

	Nine Months Ended March 31,
	2011		2010		Increase		Percent Increase
	(In Thousands)

Crude oil	$	479,080	$	278,438	$	200,642		72.1	%
Natural gas		97,509		81,102		16,407		20.2	%
Total revenues	$	576,589	$	359,540	$	217,049		60.4	%

Revenues

Our consolidated revenues increased $217.0 million in the first nine months of fiscal 2011 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher crude oil and natural gas sales volumes as a result of the ExxonMobil and Mit Acquisitions and the results of our drilling activity coupled with higher overall commodity prices. Revenue variances related to commodity prices and sales volumes are described below.

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Price Variances

Commodity prices are one of our key drivers of earnings generation and net operating cash flow. Higher overall commodity prices increased revenues by $12.2 million in the first nine months of fiscal 2011. Average natural gas prices, including a $1.62 realized gain per Mcf related to hedging activities, decreased $1.54 per Mcf during the first nine months of fiscal 2011, resulting in decreased revenues of $26.2 million. Average crude oil prices, including a $4.77 realized loss per barrel related to hedging activities, increased $6.42 per barrel, resulting in increased revenues of $38.4 million. Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during the first nine months of fiscal 2011 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash from operating activities, potentially causing us to expend less on our capital program. Lower spending on our capital program could result in a reduction of the amount of production volumes we are able to produce. We cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Higher total sales volumes in the first nine months of fiscal 2011 resulted in increased revenues of $204.8 million. Crude oil sales volumes increased 8.0 MBbls per day in the first nine months of fiscal 2011, resulting in increased revenues of $162.2 million. Natural gas sales volumes increased 21.3 MMcf per day in the first nine months of fiscal 2011, resulting in increased revenues of $42.6 million. The increase in crude oil and natural gas sales volumes in the first nine months of fiscal 2011 was primarily due to the ExxonMobil and Mit Acquisitions and to the success of our drilling program.

Below is a discussion of Costs and Expenses and Other (Income) Expense.

Costs and Expenses and Other (Income) Expense

	Nine Months Ended March 31,
	2011						2010
	Amount			Per BOE			Amount			Per BOE			Increase (Decrease) Amount
Costs and expenses	(In Thousands, except per unit amounts)
Lease operating expense
Insurance expense	$	19,919		$	2.26		$	20,383		$	3.62		$	(464	)
Workover and maintenance		16,040			1.82			14,361			2.55			1,679
Direct lease operating expense		123,528			14.02			66,563			11.81			56,965
Total lease operating expense		159,487			18.10			101,307			17.98			58,180
Production taxes		2,131			0.24			3,152			0.56			(1,021	)
DD&A		208,300			23.64			131,084			23.25			77,216
Accretion of asset retirement obligations		22,229			2.52			17,641			3.13			4,588
General and administrative expense		57,538			6.53			36,540			6.48			20,998
Gain on derivative financial instruments		(3,395	)		(0.39	)		(4,009	)		(0.71	)		614
Total costs and expenses	$	446,290		$	50.64		$	285,715		$	50.69		$	160,575

Other (income) expense
Other (income) expense – other	$	21,707		$	2.46		$	(29,657	)	$	(5.26	)	$	51,364
Interest expense		74,992			8.51			67,144			11.91			7,848
Total other (income) expense	$	96,699		$	10.97		$	37,487		$	6.65		$	59,212

Costs and expenses increased $160.6 million in the first nine months of fiscal 2011. This increase in costs and expenses was due in part to the ExxonMobil and Mit Acquisitions which increased production related expenses in the first nine months of fiscal 2011 coupled with higher general and administrative expense. Below is a discussion of costs and expenses.

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DD&A expense increased $77.2 million. This increase is principally due to improved production ($73.8 million) and a higher DD&A rate ($3.4 million). Lease operating expense increased $58.2 million in the first nine months of fiscal 2011 compared to the first nine months of fiscal 2010. This increase is primarily due to higher direct lease operating expense as a result of the ExxonMobil and Mit acquisitions.

General and administrative expense increased $21.0 million in the first nine months of fiscal 2011 principally as a result of the higher compensation expense related to Phantom and Performance Units due to our rising common stock price partially offset by lower legal and other costs.

Other (income) expense increased $59.2 million in the first nine months of fiscal 2011. This increase was primarily due to the items discussed below.

Other expense increased $51.4 million due principally to the Bridge Loan Commitment Fees of $4.5 million and the loss on the redemption of the 16% Second Lien Notes of $17.4 million in the first nine months of fiscal 2011 as compared to the gain related to the repurchased $126 million of the New Notes in the first nine months of fiscal 2010 of $26.7 million. Interest expense increased $7.8 million due to increased borrowings. On a per unit of production basis, interest expense decreased 28.4%, from $11.91/BOE to $8.51/BOE.

Income Tax Expense

Income tax expense decreased $16.9 million in the first nine months of fiscal 2011 compared to the first nine months of fiscal 2010. The effective income tax rate for the first nine months of fiscal 2011 decreased from the first nine months of fiscal 2010 from 58.1% to 12.4%.

Liquidity

Overview

Our principal requirements for capital are to fund our exploration, development and acquisition activities and to satisfy our contractual obligations, primarily for the repayment of debt and any amounts owing during the period related to our hedging positions. Our uses of capital include the following:

• drilling and completing new natural gas and oil wells;

• satisfying our contractual commitments, including payment of our debt obligations;

• constructing and installing new production infrastructure;

• acquiring additional reserves and producing properties;

• acquiring and maintaining our lease acreage position and our seismic resources;

• maintaining, repairing and enhancing existing natural gas and oil wells;

• plugging and abandoning depleted or uneconomic wells; and

• indirect costs related to our exploration activities, including payroll and other expense attributable to our

exploration professional staff.

The March 31, 2011 principal balance of our revolving credit facility, 9.25% Senior Notes due 2017 (the “9.25% Senior Notes”), 7.75% Senior Notes due 2019 (the “7.75% Senior Notes”) and 10% Senior Notes due 2013 (the “10% Senior Notes”) and related maturity dates are as follows:

·	Revolving credit facility - $119.5 million – Due March 2013;

·	9.25% Senior Notes - $750 million – Due December 2017;

·	7.75% Senior Notes - $250 million – Due June 2019; and

·	10% Senior Notes - $106.3 million – Due June 2013.

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The ExxonMobil Acquisition significantly increases our production volumes and future net revenues. The expected increase in cash flow may be used to fund capital expenditures, including the acquisition of reserves, producing properties or unproved properties, as well as payments of outstanding indebtedness.

During the nine months ended March 31, 2011, we engaged in the following capital transactions:

Conversion of 7.25% Preferred Stock

During the nine months ended March 31, 2011, in seven separate private transactions, we issued a total of 4,591,915 shares of our $.005 par value common stock in exchange for 485,530 shares of our 7.25% Preferred Stock. In addition to the common stock issued, a cash payment of $1.3 million was made to induce the conversions. The total amounts paid in cash and stock related to these five transactions to induce conversion of preferred stock were $9.0 million.

For the nine months ended March 31, 2011, we recognized $19.8 million as a reduction of equity and income available to common stockholders related to the induced conversion of 7.25% Preferred Stock. Other expenses related to the inducement are included in general and administrative expenses.

November 2010 Equity Offerings

On November 3, 2010, we closed on concurrent offerings of common and preferred stock. We sold 12 million shares of our unrestricted common stock at $20.75 per share less $0.985 per share in underwriting commissions. Net proceeds from the common stock offering were approximately $237.2 million, after deducting underwriting commissions, but before other offering expenses. We also sold 1.15 million shares of 5.625% convertible perpetual preferred stock at $250 per share less $3.75 per share (1.5%) in underwriting commissions. Net proceeds from the sale of preferred stock were approximately $283.2 million, after deducting underwriting commissions, but before other offering expenses.

Refinancing of Existing 16% Second Lien Notes

On November 29, 2010, we commenced the Tender Offer for the $222.3 million principal amount of our remaining outstanding 16% Second Lien Notes. In December 2010, a total of $219.9 million face value of 16% Second Lien Notes were tendered. The total payment of $251.0 million included $171,513 of accrued interest and $31.0 million in redemption premium.

On December 17, 2010, we commenced a call of the $4.6 million remaining outstanding 16% Second Lien Notes. On January 18, 2011, we redeemed the notes paying a cash premium of $598,059.

A total of $43.5 in redemption premiums were paid related to the call and tender of the 16% Second Lien Notes at March 31, 2011.

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9.25% Senior Notes

On December 17, 2010, EGC issued $750 million face value of 9.25% unsecured senior notes due December 15, 2017 at par.

7.75% Senior Notes

On February 25, 201, EGC issued $250 million face value of 7.75% unsecured senior notes due June 15, 2019 at par.

10% Senior Note

On April 18, 2011, we called the remaining $106.3 million of our 10% Senior Notes. The call price is 102.5% of par and is expected to close on June 15, 2011.

Amendment to Revolving Credit Facility

On November 17, 2010, we entered into an Eighth Amendment to Amended and Restated First Lien Credit Agreement to our revolving credit facility (the “Eighth Amendment”). The Eighth Amendment modifies the First Lien Credit Agreement include the following: (a) the increase of debt incurrence provisions to allow for an incremental unsecured debt basket of up to $1.0 billion, (b) the redetermination of the borrowing base to $700 million, (c) the increase of the notional amount of the revolving credit facility to $925 million, (d) the increase of the letter of credit sublimit to $300 million, and (e) the extension of the maturity date to December 15, 2014, (March 15, 2013 if any of the 10% Senior Notes remain outstanding).

We are in the process of negotiating the Ninth Amendment to Amended and Restated First Lien Credit Agreement to our revolving credit facility (the “Ninth Amendment”). If approved by the bank group, we expect that the Ninth Amendment modifies the First Lien Credit Agreement and includes the following: (a) increase in the borrowing base to $750 million, (b) reduction in the credit spread, as defined, from 275-350 basis points to 225-300 basis points, (c) increase in the preferred stock dividend basket to $17 million per year, and (d) allow the use of our captive insurance subsidiary, Energy XXI Insurance. We expect the Ninth Amendment to receive final bank approval by May 13, 2011.

BOEMRE Supplemental Bonding

On March 25, 2011, we received a letter from the BOEMRE which confirmed EGC’s continued qualification for a supplemental bonding waiver.

Potential Sale of Certain Onshore Properties

We are evaluating the potential sale of certain of our onshore Louisiana and Texas properties. The impact of any sale is not expected to have a material impact on our liquidity.

Capital Resources

Our Board of Directors approved a fiscal 2011 capital budget, excluding any potential acquisitions, but including abandonment costs, of approximately $250 million. After considering the ExxonMobil Acquisition, the Board of Directors approved an increase in our capital budget and we anticipate spending up to $380 million in capital expenditures in this fiscal period We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, and future acquisitions from cash on hand, cash flow from operations (including incremental cash flow from the ExxonMobil Properties) and borrowings under our credit facility. The capital budget may be revised based on our continued assessment of our prospect inventory, the ability to get regulatory approval of capital projects and expected future crude oil and natural gas prices.

We believe our available liquidity will be sufficient to meet our funding requirements through March 31, 2012. However, future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. There can be no assurance that cash flow from operations or other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. If an acquisition opportunity arises, we may also seek to access public markets to issue additional debt and/or equity securities. Cash flows from operations were used primarily to fund exploration and development expenditures during the first nine months of fiscal 2011.

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Net cash provided by operating activities in the first nine months of fiscal 2011 was $223.7 million as compared to $80.4 million in the first nine months of fiscal 2010. The increase is essentially due to the proceeds from sale of derivative instruments and improved production related activities. Key drivers of net operating cash flows are commodity prices, production volumes and costs and expenses. Average crude oil sales increased 58.3% in the first nine months of fiscal 2011 from the same period last year. Average natural gas prices decreased 21.2% in the first nine months of fiscal 2011 from the same period last year and natural gas sales increased 52.3% in the first nine months of fiscal 2011 from the same period last year. Changes in operating assets and liabilities increased $29.3 million primarily due to accounts payable and accrued liabilities and to prepaid expenses and other current assets.

Contractual Obligations

Information about contractual obligations at March 31, 2011 did not change materially, other than as disclosed in Notes 6 and 14 to accompanying Consolidated Financial Statements, from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended June 30, 2010.

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 “Notes to Consolidated Financial Statements”, included in our Annual Report on Form 10-K for the year ended June 30, 2010. Also refer to Note 2 “Recent Accounting Pronouncements” to accompanying Consolidated Financial Statements.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Item 1. Financial Statements – Note 2 – Recent Accounting Pronouncements of this Quarterly Report on Form 10-Q.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Market-Sensitive Instruments and Risk Management

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the fiscal year ended June 30, 2010 (the “2010 Annual Report”).

We are exposed to a variety of market risks, including commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at March 31, 2011, and from which we may incur future gains or losses from changes in market interest rates or commodity prices.

Hypothetical changes in commodity prices and interest rates chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based upon conditions of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Commodity Price Risk

We utilize commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, three-way collars and zero-cost collars. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded in income, whereas gains and losses from the settlement of hedging contracts are recorded in crude oil and natural gas revenues.

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With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX) plus the difference between the purchased put and the sold put strike price.

We typically hedge up to three years. We have minimum and maximum hedge limits in our first lien revolving credit facility. Typically we have 60% to 80% of our production volumes hedged in prompt twelve months, 30% to 40% hedged during the second twelve months and 20% to 30 % hedged during the third twelve months. We also vary the mix of hedges and modify the percentage hedged based upon our bias for price expectations.

Based on the March 31, 2011 published forward commodity price curves for the underlying commodities, a price increase of 10% per barrel for crude oil would decrease the fair value of our net commodity derivative asset by approximately $102.4 million. A price increase of 10% per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $26.7 million.

Derivative instruments are reported on the balance sheet at fair value as short-term or long-term derivative financial instruments assets or liabilities.

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our ultimate realized gain or loss with respect to commodity price fluctuations will depend on the future exposures that arise during the period as well as our hedging strategies and commodity prices at the time.

We will generally invest cash equivalents in high-quality credit instruments consisting primarily of money market funds with maturities of 90 days or less. We do not expect any material loss from cash equivalents and therefore we believe its interest rate exposure on invested funds is not material.

ITEM 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of certain members of our management, including the Chief Executive Officer and Chief Financial Officer, we completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13a –15(f) and 15d –15(f) under the Exchange Act) during our quarterly period ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. Legal Proceedings

We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations.

ITEM 1A. Risk Factors

Our business faces many risks. Any of the risks discussed below or elsewhere in this Quarterly Report on Form 10-Q or our other SEC filings, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our common stock, please refer to the section entitled “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended June 30, 2010 as supplemented by the risk factors set forth below. There has been no material change in the risk factors set forth in our Annual Report on Form 10-K for the year ended June 30, 2010 other than those set forth below. For further information, see Part I—Item 1A—Risk Factors in our Annual Report on Form 10-K for the year ended June 30, 2010.

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ITEM 6. Exhibits

The following exhibits are filed as part of this report.

Exhibit Number	Exhibit Title	Incorporated by Reference to the Following

4.1	Indenture dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited and the other Guarantors named therein and Wells Fargo Bank, National Association, as trustee	4.1 to the Company’s Current Report on Form 8-K filed on February 26, 2011 with the SEC (File/Film No. 001-33628/ 101160431)
4.2	Registration Rights Agreement dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited and the other Guarantors named therein and the Initial Purchasers named therein	4.2 to the Company’s Current Report on Form 8-K filed on February 26, 2011 with the SEC (File/Film No. 001-33628/ 101160431)
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Furnished herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Furnished herewith
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, Energy XXI (Bermuda) Limited has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ENERGY XXI (BERMUDA) LIMITED


	By:	/S/ DAVID WEST GRIFFIN
		David West Griffin
		Duly Authorized Officer and Chief Financial Officer


	By:	/S/ HUGH A. MENOWN
		Hugh A. Menown
		Duly Authorized Officer and Senior Vice President, Chief Accounting Officer and Chief Information Officer

Date: April 28, 2011

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EXHIBIT INDEX

Exhibit Number	Exhibit Title	Incorporated by Reference to the Following

4.1	Indenture dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited and the other Guarantors named therein and Wells Fargo Bank, National Association, as trustee	4.1 to the Company’s Current Report on Form 8-K filed on February 26, 2011 with the SEC (File/Film No. 001-33628/ 101160431)
4.2	Registration Rights Agreement dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited and the other Guarantors named therein and the Initial Purchasers named therein	4.2 to the Company’s Current Report on Form 8-K filed on February 26, 2011 with the SEC (File/Film No. 001-33628/ 101160431)
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Furnished herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Furnished herewith
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith

Attached files

Energy XXI Ltd Reports

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