UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2009

OR

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

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)	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)
Registrant's telephone number, including area code	441-295-2244

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.           Yes  x    No 

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

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

Large accelerated filer        Accelerated filer x       Non-accelerated filer        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  x

As of January 31, 2010, there were 50,794,079 shares outstanding of the registrant’s common stock, par value $0.005 per share.

TABLE OF CONTENTS

		Page
PART I — FINANCIAL INFORMATION
ITEM 1.	Financial Statements	3
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	32
ITEM 4.	Controls and Procedures	33
PART II — OTHER INFORMATION
ITEM 1.	Legal Proceedings	34
ITEM 1A.	Risk Factors	34
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
ITEM 4.	Submission of Matters to a Vote of Security Holders	35
ITEM 6.	Exhibits	36
SIGNATURES		37

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PART I - FINANCIAL INFORMATION

ITEM 1.     Financial Statements

ENERGY XXI (BERMUDA) LIMITED

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	December 31,			June 30,
	2009			2009
ASSETS	(Unaudited)
Current Assets
Cash and cash equivalents	$	23,270		$	88,925
Accounts receivable
Oil and natural gas sales		68,924			40,087
Joint interest billings		7,353			17,624
Insurance and other		14,069			2,562
Prepaid expenses and other current assets		37,611			16,318
Royalty deposit		1,638			1,746
Derivative financial instruments		24,567			31,404
Total Current Assets		177,432			198,666
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment
Oil and natural gas properties - full cost method of accounting		1,365,977			1,102,596
Other property and equipment		8,259			9,149
Total Property and Equipment – net		1,374,236			1,111,745
Other Assets
Derivative financial instruments		6,435			3,838
Restricted cash		2,160			—
Debt issuance costs, net of accumulated amortization		12,251			14,413
Total Other Assets		20,846			18,251
Total Assets	$	1,572,514		$	1,328,662
LIABILITIES
Current Liabilities
Accounts payable	$	74,219		$	81,025
Note payable		6,549			—
Accrued liabilities		43,671			36,180
Asset retirement obligations		85,733			66,244
Derivative financial instruments		19,551			15,732
Current maturities of long-term debt		3,865			4,107
Total Current Liabilities		233,588			203,288
Long-term debt, less current maturities, face value of $766,367,000 and $858,720,000 at December 31, 2009 and June 30, 2009, respectively		815,664			858,720
Deferred income taxes		32,189			26,889
Asset retirement obligations		86,935			77,955
Derivative financial instruments		507			4,818
Other		—			29,492
Total Liabilities		1,168,883			1,201,162
Commitments and Contingencies (Note 14)
Stockholders’ Equity
Preferred stock, $0.01 par value, 2,500,000 shares authorized and 1,100,000 shares and no shares issued and outstanding at December 31, 2009 and June 30, 2009, respectively		11			—
Common stock, $0.005 par value, 200,000,000 shares authorized and 50,819,323 and 29,283,051 shares issued and 50,804,389 and 29,150,116 shares outstanding at    December 31, 2009 and June 30, 2009, respectively		253			146
Additional paid-in capital		899,494			604,724
Accumulated deficit		(512,053	)		(515,867	)
Accumulated other comprehensive income, net of income taxes		15,926			38,497
Total Stockholders’ Equity		403,631			127,500
Total Liabilities and Stockholders’ Equity	$	1,572,514		$	1,328,662

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						Six Months Ended
	December 31,						December 31,
	2009			2008			2009			2008
Revenues
Oil sales	$	98,050		$	66,668		$	164,343		$	148,730
Natural gas sales		26,456			40,184			45,070			77,866
Total Revenues		124,506			106,852			209,413			226,596
Costs and Expenses
Lease operating expense		35,050			37,564			60,475			72,562
Production taxes		1,007			1,878			2,282			3,914
Impairment of oil and gas properties		—			459,109			—			459,109
Depreciation, depletion and amortization		44,972			65,002			80,323			127,411
Accretion of asset retirement obligations		6,160			2,433			11,306			4,894
General and administrative expense		14,022			6,236			22,088			12,471
Loss (gain) on derivative financial instruments		1,956			(10,037	)		(4,323	)		(11,901	)
Total Costs and Expenses		103,167			562,185			172,151			668,460
Operating Income (Loss)		21,339			(455,333	)		37,262			(441,864	)
Other Income (Expense)
Other income		27,658			2,104			29,644			3,438
Interest expense		(24,345	)		(21,168	)		(45,307	)		(43,473	)
Total Other Income (Expense)		3,313			(19,064	)		(15,663	)		(40,035	)
Income (Loss) Before Income Taxes		24,652			(474,397	)		21,599			(481,899	)
Income Tax Expense (Benefit)		8,206			(45,194	)		17,453			(48,045	)
Net Income (Loss)		16,446			(429,203	)		4,146			(433,854	)
Preferred Stock Dividends		332			—			332			—
Net Income (Loss) Available for Common Stockholders	$	16,114		$	(429,203	)	$	3,814		$	(433,854	)
Earnings (Loss) Per Share
Basic	$	0.48		$	(14.88	)	$	0.12		$	(15.01	)
Diluted	$	0.46		$	(14.88	)	$	0.13		$	(15.01	)
Weighted Average Number of Common Shares Outstanding
Basic		33,788			28,835			31,470			28,896
Diluted		35,815			28,835			32,627			28,896

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						Six Months Ended
	December 31,						December 31,
	2009			2008			2009			2008
Cash Flows From Operating Activities
Net income (loss)	$	16,446		$	(429,203	)	$	4,146		$	(433,854	)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Deferred income tax expense (benefit)		8,206			(45,910	)		17,453			(48,761	)
Change in derivative financial instruments		(4,759	)		(8,520	)		(17,115	)		(9,862	)
Accretion of asset retirement obligations		6,160			2,433			11,306			4,894
Depreciation, depletion, and amortization		44,972			65,002			80,323			127,411
Impairment of oil and gas properties		—			459,109			—			459,109
Amortization of deferred gain on debt		(29,024	)		(1,148	)		(30,867	)		(1,466	)
Amortization and write-off of debt issuance costs		3,341			988			4,459			2,000
Stock-based compensation		839			602			1,742			865
Changes in operating assets and liabilities
Accounts receivable		(53,661	)		(460	)		(38,385	)		53,608
Prepaid expenses and other current assets		(14,489	)		14,028			(21,185	)		(12,706	)
Asset retirement obligations		(32,615	)		(7,004	)		(42,449	)		(13,484	)
Accounts payable and other liabilities		(10,389	)		(25,472	)		(7,149	)		(32,254	)
Net Cash Provided by (Used in) Operating Activities		(64,973	)		24,445			(37,721	)		95,500
Cash Flows from Investing Activities
Acquisitions		(274,518	)		—			(274,518	)		—
Capital expenditures		(37,670	)		(94,761	)		(47,811	)		(180,884	)
Insurance payments received		45,199			—			53,178			—
Restricted cash		(1,634	)		—			(2,160	)		—
Other		46			(255	)		134			(255	)
Net Cash Used in Investing Activities		(268,577	)		(95,016	)		(271,177	)		(181,139	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		294,527			—			294,527			—
Dividends to shareholders		—			(1,453	)		—			(1,453	)
Proceeds from long-term debt		75,837			105,239			75,837			249,990
Payments on long-term debt		(118,782	)		(2,320	)		(123,443	)		(152,403	)
Purchase of bonds		—			(32,563	)		—			(91,355	)
Other		(2,063	)		(401	)		(3,678	)		(868	)
Net Cash Provided by Financing Activities		249,519			68,502			243,243			3,911
Net Decrease in Cash and Cash Equivalents		(84,031	)		(2,069	)		(65,655	)		(81,728	)
Cash and Cash Equivalents, beginning of period		107,301			89,303			88,925			168,962
Cash and Cash Equivalents, end of period	$	23,270		$	87,234		$	23,270		$	87,234

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

Note 1 — Basis of Presentation

Nature of Operations.  Energy XXI (Bermuda) Limited (“Energy XXI”) was incorporated in Bermuda on July 25, 2005.  Energy XXI (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company with its principal wholly owned subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), 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.

On December 5, 2008, we formed a new company, Energy XXI, Inc. which is now the parent company of our U.S. operations.  The company was capitalized by Energy XXI (US Holdings) Limited’s contribution of all of the capital stock of Energy XXI USA, Inc. and certain Energy XXI Gulf Coast, Inc.’s bonds.

Principles of Consolidation and Reporting. Our 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 consolidated financial statements for the periods presented herein are unaudited and do not contain all information required by generally accepted accounting principles (“GAAP”) to be included in a full set of financial statements.  In the opinion of management, all material adjustments necessary to present fairly the results of operations have been included.  All such adjustments are of a normal, recurring nature.  The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.  These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended June 30, 2009.

Use of Estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the 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.

Restricted Cash.  At December 31, 2009, we had $2.2 million in restricted cash securing certain letters of credit.  This amount is classified as non-current at December 31, 2009.

Common Stock.  At the Company’s 2009 Annual General Meeting of Shareholders (AGM) held on December 11, 2009, the 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 the Board of Directors.  In January 2010, the Board of Directors approved a 1:5 stock consolidation or reverse stock split effective January 29, 2010.  Accordingly, all common shares, incentive plans and related amounts for all periods presented reflect the stock consolidation.

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Note 2 – Recent Accounting Pronouncements

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

Fair Value Measurements and Disclosures. The FASB has issued new guidance on improving disclosures about fair value measurements. The new standard requires some 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 standard will now require:

-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.

In addition, the new standard 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 standard 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 are still in the process of evaluating the impact, if any, on our consolidated financial position and results of operations.

Business Combinations.  In December 2007, the FASB issued new guidance on business combinations. The new standard provides revised guidance on how acquirers recognize and measure the consideration transferred, identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired in a business combination. The new standard also expands required disclosures surrounding the nature and financial effects of business combinations. The standard is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. We adopted the new guidance effective July 1, 2009.

As discussed in Note 4, on December 22, 2009, we closed on the acquisition of certain Gulf of Mexico shelf properties and we accounted for such acquisition under the new business combination guidance.

Subsequent Events.  In May 2009, the FASB issued new guidance on subsequent events. The standard provides guidance on management’s assessment of subsequent events and incorporates this guidance into accounting literature. The standard is effective prospectively for interim and annual periods ending after June 15, 2009. The implementation of this standard did not have a material impact on our consolidated financial position and results of operations. The Company has evaluated subsequent events through February 3, 2010, the date of issuance of our consolidated financial position and results of operations.  

Variable Interest Entities.  In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities. The guidance affects the overall consolidation analysis and requires enhanced disclosures on involvement with variable interest entities. The guidance is effective for fiscal years beginning after November 15, 2009.  The implementation of this standard is not expected to have a material impact on our consolidated financial position and results of operations.

            Accounting Standards Codification.  In June 2009, the FASB Accounting Standards Codification (“Codification”) was issued. The Codification is the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The implementation of this standard did not have a material impact on our consolidated financial position and results of operations.

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Proposed 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 (Topic 932) with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and is effective for our fiscal year ended June 30, 2010.  We are still in the process of evaluating the impact, if any, on our consolidated financial position and results of operations. 

Unvested Share-based Payment Awards.  On July 1, 2009, we adopted an update to accounting standards related to accounting for instruments granted in share-based payment transactions as participating securities.  This update provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share.  The implementation of this standard did not have a material impact on our consolidated financial position and results of operations.  All earnings per share amounts presented were not materially impacted.

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.  We also allocate a portion of our acquisition costs to unevaluated properties based on relative value.  Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

We assess the impairment of our evaluated oil and gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capital costs. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and gas reserves could be subject to significant revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.

  Ceiling Test. Under the full cost method of accounting, we are required to perform each quarter, a “ceiling test” 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, exceeds the present value of estimated future net cash flows discounted at 10 percent, 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 period-end commodity prices and exclude future cash outflows related to estimated abandonment costs.  As of the reported balance sheet date, capitalized costs of an oil and gas producing company may not exceed the full cost limitation calculated under the above described rule based on current spot market prices for oil and natural gas. However, if prior to the balance sheet date, the company enters into certain hedging arrangements for a portion of its future natural gas and oil production, thereby enabling the company to receive future cash flows that are higher than the estimated future cash flows indicated by use of the spot market price as of the reported balance sheet date, these higher hedged prices are used if they qualify as cash flow hedges under the authoritative guidance that applies to derivative instruments and hedging activities.

Because of the significant decline in crude oil and natural gas prices, coupled with the impact of Hurricanes Gustav and Ike, we recognized a non-cash write-down of the net book value of our oil and gas properties of $117.9 million and $459.1 million in the third and second quarters of fiscal 2009, respectively.   The write-downs were reduced by $179.9 million and $203.0 million pre-tax as a result of our hedging program in the third and second quarters of fiscal 2009, respectively.  No write-downs were required for the first or second quarters of fiscal 2010.

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Note 4 – Acquisitions

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 $273.1 million.  For accounting purposes, the acquisition was recorded effective November 20, 2009 as that was the date that the Company gained control of the assets acquired and liabilities assumed. Therefore, revenue and expenses related to these properties are included in the December 31, 2009 results for the period November 20, 2009 to December 31, 2009. The transaction was financed through proceeds received from common and perpetual convertible preferred stock offerings (See Note 12).

The acquisition was accounted for under the purchase method of accounting in accordance with the new business combination accounting guidance we adopted effective July 1, 2009 (See Note 2). 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 market values, while transaction and integration costs associated with the acquisition were expensed as incurred. The initial accounting for the business combination is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analysis are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date.

The transaction involves mirror-image non-operated interests in the same group of properties we purchased from Pogo Producing Company in June 2007.  The properties include 30 fields of which production is approximately 77 percent crude oil and 80 percent of which is already operated by us.  Offshore leases included in the purchase total nearly 33,000 net acres.

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

Oil and natural gas properties – evaluated	$	288,587
Oil and natural gas properties – unevaluated		41,362
Net working capital		1,008
Asset retirement obligation liabilities		(57,827	)
Cash paid	$	273,130

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

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: (i) oil and gas reserves; (ii) future operating and development costs; (iii) future oil and gas prices; and (iv) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligation liabilities include estimates of: (i) plug and abandonment costs per well and related facilities; (ii) remaining life per well and facilities; and (iii) a credit adjusted risk-free interest rate.

The following amounts of the Mit Acquisition properties’ revenue and earnings included in our consolidated statement of operations for the six months ended December 31, 2009 and the summarized unaudited pro forma financial information for the six months ended December 31, 2009 and 2008, respectively, assumes that the Mit Acquisition had occurred on July 1, 2008. 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 acquisition as of July 1, 2008 or the results that will be attained in the future (in thousands).

	Revenue		Earnings (1)
Mit Acquisition properties from November 21, 2009 through December 31, 2009	$	21,940	$	15,779
Supplemental pro forma for July 1, 2009 through December 31, 2009	$	266,253	$	186,141
Supplemental pro forma for July 1, 2008 through December 31, 2008	$	334,165	$	212,257

(1) Earnings includes revenue less production costs.

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Note 5 – Property and Equipment

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

	December 31, 2009		June 30, 2009
Oil and gas properties
Proved properties	$	2,613,844	$	2,227,462
Less: Accumulated depreciation, depletion, amortization and impairment		1,341,386		1,262,355
Proved properties—net		1,272,458		965,107
Unproved properties		93,519		137,489
Oil and gas properties—net		1,365,977		1,102,596
Other property and equipment		14,541		14,508
Less: Accumulated depreciation		6,282		5,359
Other property and equipment—net		8,259		9,149
Total property and equipment	$	1,374,236	$	1,111,745

Property costs incurred for the six months ended December 31, 2009 consist of the following (in thousands):

Oil and gas activities
Development	$	50,796
Exploration		13,643
Administrative and other		248
Capital expenditures		64,687
Property acquisitions		331,213
Insurance proceeds and other net		(53,455	)
Total costs incurred	$	342,445

Note 6 – Long-term Debt

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

	December 31, 2009
	Face Value		Premium (Discount)			Recorded Value		June 30, 2009
First lien revolver	$	149,074	$	—		$	149,074	$	234,531
Second lien – 16%		278,511		67,835			346,346		—
Private placement – 16%		60,111		(18,538	)		41,573		—
Total second lien		338,622		49,297			387,919		—
High yield facility – 10% Senior notes		276,500		—			276,500		624,000
Put premium financing		5,456		—			5,456		3,851
Capital lease obligation		580		—			580		445
Total debt		770,232		49,297			819,529		862,827
Less current maturities		3,865		—			3,865		4,107
Total long-term debt	$	766,367	$	49,297		$	815,664	$	858,720

At December 31, 2009, included in the face value of the 16% Second lien notes is $620,000 amount of Payable-in-Kind 2% interest that was paid in the form of additional 16% Second lien notes on December 15, 2009.

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Maturities of long-term debt as of December 31, 2009 are as follows (in thousands):

Twelve Months Ending December 31,
2010	$	3,865
2011		151,063
2012		182
2013		276,500
2014		338,622
Total	$	770,232

First Lien Revolver

This facility was entered into by our subsidiary, EGC. This facility has a face value of $700 million and matures on June 8, 2011. The facility was amended during the six months ended December 31, 2009 to permit the issuance of second lien notes discussed below, reduce the borrowing base from $240 million to $199 million and increase the interest rates. 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 percent to 3.50 percent or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75 percent to 2.50 percent. The credit facility is secured by mortgages on at least 85 percent of the value of our proved reserves.

Our first lien revolving credit facility requires us to maintain certain financial covenants, as defined. Specifically, EGC may not permit its total leverage ratio to be more than 4.5 to 1.0 with certain reductions in this ratio over time (which was amended on April 6, 2009), our interest rate coverage ratio to be less than 3.0 to 1.0, a secured debt ratio to be more than 2.5 to 1.0, or our current ratio (in each case as defined in our first lien revolving credit facility) to be less than 1.0 to 1.0, in each case, as of the end of each fiscal quarter. In addition, we are subject to various other covenants including, but not limited to, those limiting dividends and other payments, the incurrence of debt, changes in control, entering into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr., Steven A. Weyel and David West Griffin in their current executive positions, subject to certain exceptions in the event of death or disability to one of these individuals.

The first lien revolving credit facility also contains customary events of default, including, but not limited to non-payment of principal when due, non-payment of interest or fees and other amounts after a grace period, failure of any representation or warranty to be true in all material respects when made or deemed made, defaults under other debt instruments (including the indenture governing the notes), commencement of a bankruptcy or similar proceeding by or on behalf of us or a guarantor, judgments against us or a guarantor, the institution by us to terminate a pension plan or other ERISA events, any change in control, loss of liens, failure to meet financial ratios, and violations of other covenants subject, in certain cases, to a grace period.  As of December 31, 2009, we are in compliance with all covenants.

In February 2010, EGC and its lenders expect to amend the First Lien Revolver to:

•  Extend the maturity from June, 2011 to February, 2013;

•  Increase the borrowing base from $199 million to $350 million;

•  Reduce the face amount from $700 million to $400 million;

•  Amend the total leverage ratio covenant to require that the total leverage ratio not exceed 3.75 to 1.0 starting in March, 2010 and to not exceed 3.50 to 1.0 starting June 30, 2010; and

•  Amend the covenant to maintain only John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of death or disability.

- 11 -

High Yield Facility

On June 8, 2007 our subsidiary, EGC, completed a $750 million private offering of 10 percent Senior Notes due 2013 (“Old Notes”).  As part of the private offering EGC agreed to use its best efforts to complete an exchange offer, which it completed on October 16, 2007.  In the exchange offer, the Old Notes were exchanged for $750 million of 10 percent Senior Notes due 2013 that have been registered under the Securities Act of 1933 (“New Notes”), with terms substantially the same as the Old Notes.  All of the issued and outstanding Old Notes were exchanged for New Notes.  We did not receive any cash proceeds from the exchange offer.

The notes are guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We have the right to redeem the new notes under various circumstances and are required to make an offer to repurchase the new notes upon a change of control and from the net proceeds of asset sales under specified circumstances.

The Company had previously purchased a total of $126.0 million total face amount of the New Notes at an average cost of 72.13, or $90.9 million, plus accrued interest of $3.3 million for a total cost of $94.2 million, reflecting a total potential gain of $35.1 million pre-tax.  As discussed below, on November 12, 2009, the Company issued $278 million of Secured Second Lien 16% Notes (“Second Lien Notes”), in exchange for $347.5 million of New Notes. In conjunction with the exchange, the Company contributed the $126 million face value of notes they had purchased, to EGC, who retired the notes. During the six months ended December 31, 2009, the Company recognized a $26.7 million gain related to the repurchased and retired $126 million of New Notes.

We believe that the fair value of the $276.5 million of New Notes outstanding as of December 31, 2009 was $252.2 million.

16% Second Lien Notes

On November 12, 2009, the Company closed on an offering of 16% Second Lien Notes as follows:

1)   A total of $278 million of 16% Second Lien Notes were issued in exchange for $347.5 million of New Notes

2)   A total of $60 million in 16% Second Lien Notes were issued for cash. For each $1 million in Second Lien Notes purchased for cash, the purchaser also received 44,082 shares of the Company’s common stock (2,644,944 common shares in total)

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

Under the terms of the Second Lien Notes, the Company is required to register notes having identical terms and conditions as the Second Line Notes with the Securities and Exchange Commission (“SEC”) after which the Second Lien Notes will be exchanged for the registered notes. The Company filed a Registration Statement on Form S-4 on December 23, 2009 which was amended on January 20, 2010.

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

For accounting purposes, the $60 million in Second Lien Notes that the Company received cash for 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 the common stock closing price of $10.60 per share on November 12, 2009. Based on these relative fair market values, the $60 million in Second Lien Notes were 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 in Second Lien Notes and their recorded value will be amortized as an increase in interest expense over the life of the Second Lien Notes.

We believe that the fair value of the $338.6 million face value of the 16% Second Lien Notes outstanding as of December 31, 2009 was $372.5 million.

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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 first lien revolver. The hedge financing is structured to mature when the put settles so that we realize the value net of hedge financing. As of December 31, 2009 and June 30, 2009, our outstanding hedge financing totaled $5.5 million and $3.9 million, respectively.

Interest Expense

For the three months and six months ended December 31, 2009 and 2008, interest expense consisted of the following (in thousands):

	Three Months Ended					Six Months Ended
	December 31,					December 31,
	2009			2008		2009			2008
Revolving credit facility	$	2,772		$	3,574	$	6,109		$	6,469
High yield notes		10,915			16,352		26,669			34,274
16% Second Lien Notes		7,211					7,211
Amortization of debt issue cost - Revolving credit facility		500			274		904			572
Amortization of debt issue cost - High yield notes		630			714		1,344			1,428
Amortization of debt issue cost - 16% Second Lien Notes		14			—		14			—
Premium amortization - 16% exchange Second Lien Notes		521			—		521			—
Discount amortization - 16% private placement Second Lien Notes		(1,895	)		—		(1,895	)		—
Write-off of debt issue costs - Retirement of $126 million in bonds		1,750			—		1,750			—
Write-off of debt issue costs – Reduction in revolving credit facility		447			—		447			—
Put premium financing and other		1,480			254		2,233			730
	$	24,345		$	21,168	$	45,307		$	43,473

Note 7 – Note Payable

On July 22, 2009, we entered into a note to finance a portion of our insurance premiums.  The note is for a total face amount of $19.5 million and bears interest at an annual rate of 3.2 percent.  The note amortizes over nine months and the balance at December 31, 2009 was $6.5 million.

Note 8 – Asset Retirement Obligations

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

Balance at June 30, 2009	$	144,199
Liabilities acquired		57,930
Liabilities incurred		1,682
Liabilities settled		(42,449	)
Accretion expense		11,306
Total balance at December 31, 2009		172,668
Less current portion		85,733
Long-term balance at December 31, 2009	$	86,935

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

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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.

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.

Cash settlements, net of the amortization of purchased put premiums on effective cash flow hedges for the three months ended December 31, 2009 resulted in an increase in crude oil and natural gas sales in the amount of $13.7 million. For the three months ended December 31, 2009, we recognized a loss of approximately $0.5 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $4.1 million and an unrealized loss of approximately $5.5 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 three months ended December 31, 2008 resulted in an increase in crude oil and natural gas sales in the amount of $20.3 million. For the three months ended December 31, 2008, we recognized a gain of approximately $6.8 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $1.6 million and an unrealized gain of approximately $1.6 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 six months ended December 31, 2009 resulted in an increase in crude oil and natural gas sales in the amount of $30.7 million.  For the six months ended December 31, 2009, we recognized a loss of approximately $0.7 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $10.2 million and an unrealized loss of approximately $5.2 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 six months ended December 31, 2008 resulted in a decrease in crude oil and natural gas sales in the amount of $23.6 million. For the six months ended December 31, 2008, we recognized a gain of approximately $7.4 million related to the net price ineffectiveness of our hedged crude oil and natural gas contracts and a realized gain of approximately $2.2 million and an unrealized gain of approximately $2.3 million, respectively, on derivative financial transactions that did not qualify for hedge accounting.

- 14 -

As of December 31, 2009, we had the following contracts outstanding (Asset and Fair Value Gain in thousands):

	Crude Oil										Natural Gas
	Volume (MBbls)		Contract Price (1)		Total						Volume (MMMBtus)		Contract Price (1)		Total						Total
Period					Asset (Liability)			Fair Value Gain (Loss)							Asset (Liability)			Fair Value Gain (Loss)			Asset (Liability)			Fair Value Gain (Loss) (2)
Put Spreads
01/10 – 12/10		1,095	$	60.00/$75.00	$	3,313						790	$	6.00/$8.00	$	22		$	(1,501	)	$	3,335		$	(1,501	)
01/11 – 12/11		543		60.00/75.00		2,511																2,511
						5,824										22			(1,501	)		5,846			(1,501	)
Puts
01/10 – 12/10		1,278		72.14		(2,356	)															(2,356	)
01/11 – 12/11		634		72.14		163																163
						(2,193	)															(2,193	)
Swaps
01/10 – 12/10		1,236		65.51		(13,953	)	$	8,479			5,395		5.75		(5,528	)		988			(19,481	)		9,467
01/11 – 12/11		292		65.62		(2,333	)		1,158			4,380		7.05		1,953			(1,236	)		(380	)		(78	)
						(16,286	)		9,637							(3,575	)		(248	)		(19,861	)		9,389
Collars
01/10 – 12/10		433		77.31/106.15		1,398			(326	)												1,398			(326	)
Three-Way Collars
01/10 – 12/10		224	51.79/66.79/82.04			(1,192	)		689			7,600	6.00/8.24/10.09			14,501			(7,369	)		13,309			(6,680	)
01/11 – 12/11												3,650	5.50/7.50/10.55			3,896			(2,378	)		3,896			(2,378	)
						(1,192	)		689							18,397			(9,747	)		17,205			(9,058	)
Total Gain (Loss) on Derivatives					$	(12,449	)	$	10,000						$	14,844		$	(11,496	)	$	2,395		$	(1,496	)

 (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 December 31, 2009 (In thousands):

		Asset Derivatives		Liability Derivatives
		Balance Sheet Location	Fair Value	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under Statement 133
	Commodity Contracts	Derivative financial instruments		Derivative financial instruments
		Current	$16,298	Current	$17,435
		Non-current	5,613	Non-current	2,131
			21,911		19,566
	Interest Rate Contracts			Derivative financial instruments
				Current	1,952
Total derivatives designated as hedging instruments under Statement 133
			21,911		21,518
Derivatives not designated as hedging instruments under Statement 133
	Commodity Contracts	Derivative financial instruments		Derivative financial instruments
		Current	13,164	Current	8,784
		Non-current	6,599	Non-current	428
			19,763		9,212
Total derivatives			$41,674		$30,730

The following table quantifies the fair values, on a gross basis, the effect of derivatives on our financial performance and cash flows for the six months ended December 31, 2009 (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 Statement 133 Cash Flow Hedging Relationships	Amount of (Gain) Loss Recognized in Income on Derivative (Effective Portion)
Commodity Contracts	$23,560	Revenue	$(30,744)	Gain / (Loss) on derivative financial instruments	$680
Interest Rate Contracts	(989)	Interest expense	(1,928)	Gain / (Loss) on derivative financial instruments	-
Total	$22,571		$(32,672)		$680

Derivatives Not Designated as Hedging Instruments under Statement 133		Amount of (Gain) Loss Recognized in Income on Derivate
	Location of (Gain) Loss Recognized in Income on Derivative
Commodity Contracts	(Gain) loss on derivative financial instruments	$(5,003)

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We have reviewed the financial strength of our hedge counterparties and believe the credit risk to be minimal.  At December 31, 2009, we had no deposits for collateral with our counterparties.

On June 26, 2006, we entered into an interest rate costless collar to mitigate the risk of loss due to changes in interest rates.  The dollar amount hedged was $75 million with the interest rate collar being 5.45 percent to 5.75 percent.  At December 31, 2009, we had deferred $1.3 million, net of tax benefit, in losses in OCI related to this instrument.

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

Accumulated other comprehensive income – June 30, 2009	$	38,497
Hedging activities:
Commodity
Change in fair value (loss)		(37,160	)
Reclassified to income		13,600
Interest rate
Change in fair value (loss)		(279	)
Reclassified to income		1,268
Accumulated other comprehensive income – December 31, 2009	$	15,926

The amounts expected to be reclassified to income in the next twelve months are $11.1 million income on our commodity hedges and a $2.0 million loss on our interest rate hedge.

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 (“U.S.”); 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 of our oil and gas properties due to the steep decline in global energy prices over that same time period.  As a result, we are in a position of cumulative reporting losses for the current and preceding reporting periods.  The volatility of energy prices and uncertainty of when energy prices may rebound is problematic and not readily determinable by our management.  At this date, this general fact pattern does not allow us to project sufficient sources of future taxable income to offset our tax loss carryforwards and net deferred tax assets in the U.S. Under these current circumstances, it is management’s opinion that the realization of these tax attributes beyond the reversal of existing taxable temporary differences does not reach the “more likely than not” criteria under authoritative guidance that applies to income taxes.  As a result, we have established a valuation allowance of $175.0 million, at June 30, 2009, against our U.S. net deferred tax assets and the change in the valuation allowance during that year was the same amount.

In establishing the valuation allowance against the U.S. net deferred tax assets at June 30, 2009, the Company relied upon the future reversal of taxable temporary differences associated with deferred income reported in Other Comprehensive Income (“OCI”) as a source of future taxable income as required by GAAP. This had the practical effect of reducing the amount of the valuation allowance needed against the Company’s U.S. net deferred tax assets. For the three months and six months ended December 31, 2009, the Company experienced a decrease in OCI of $15,992,000 and $34,963,000. This reduction in the deferred income associated with OCI has caused the Company to increase the valuation allowance during the three months and six months ended December 31, 2009 by $5,597,000 and $12,237,000 due to the realization concerns related to its U.S. deferred tax assets (primarily the federal net operating loss carryforward).

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 $5,214,000 for the six months ended December 31, 2009. The cumulative withholding obligation is $32,186,000 through December 31, 2009.

Our effective tax rate for the three months and six months ended December 31, 2009 and 2008 was approximately 33.3% and (9.5) % and 80.8% and (10.0) %, respectively. As discussed above, the significant variance is primarily due to the increase 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 for which no deduction for interest expense is currently allowable to the U.S. group.

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

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 any increase in stock price over the performance period, multiplied by the number of units that vest. The initial stock price used in determining the change in stock price is $7.40 per share.

TSR Performance-Based Units. For each TSR Performance-Based Unit, the employee will receive a cash payment equal to the grant date unit 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 TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier, as set forth below.

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

2)   If the Total Shareholder Return is above 5% but less than 15%, then the TSR Unit Modifier is calculated by multiplying the TSR percentage by five and adding 25%.

3)   If the Total Shareholder Return is above 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.

4)   If the Total Shareholder Return is greater than or equal to 30%, then the TSR Unit Number Modifier is set at 200%.

In addition, the employee may have the opportunity to earn additional compensation based on the Company’s Total Shareholder Return at the end of the third Performance Period.

At our discretion, at the time the Phantom Stock units and Performance 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 Units become immediately vested and payable. Although historically, we have paid all vesting awards in cash, for the fiscal 2010 award, we may pay 25% in common stock.

As of December 31, 2009, we have 1,414,661 unvested Phantom Stock units and 317,775 unvested Performance Units.  For the three months and six months ended December 31, 2009 and 2008, we recognized compensation expense (benefit) of $2.4 million, $3.7 million, $(0.9) million and $(1.1) million, respectively, related to our Phantom Stock units.  For the three months and six months ended December 31, 2009, we recognized compensation expense of $2.3 million and $3.1 million, respectively, related to our Performance Units.  A liability has been recognized as of December 31, 2009 in the amount of $6.4 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.

- 18 -

Restricted Shares activity is as follows:

			Average
			Grant-date
	Number		Fair value
	Of Shares		Per Share
Non-vested at June 30, 2009		141,963	$	25.90
Vested during the six months ended December 31, 2009		40,821
Non-vested at December 31, 2009		101,142	$	26.40

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 service period.  For the three months and six months ended December 31, 2009 and 2008, we recognized compensation expense of $0.4 million, $0.8 million, $0.5 million and $0.9 million, respectively, related to our Restricted Shares.  As of December 31, 2009 there was approximately $1.9 million of unrecognized compensation cost related to non-vested Restricted Shares.  We expect approximately $0.8 million to be recognized over fiscal 2010, $1.0 million to be recognized during the fiscal year ended 2011 and $0.1 million 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 Common Stock that have either been purchased by us on the open market or that have been newly issued by us.  During the six months ended December 31, 2009 and 2008, we issued 108,269 shares and 77,370 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan which allows employees to purchase common stock at a 15 percent discount from the lower of the common stock closing price on the first or last day of the period.  The current period is from July 1, 2009 to December 31, 2009.  For the three months and six months ended December 31, 2009 and 2008, we had charged $46,000, $93,000, $34,000 and $34,000, respectively, to compensation expense related to this plan.  The plan has a limit of 1,000,000 common shares.  During the six months ended December 31, 2009, we issued 85,082 shares under the Employee Stock Purchase Plan.

Defined Contribution Plans.  Our employees are covered by a discretionary noncontributory profit sharing plan.  The plan provides for annual employer contributions up to 10 percent of annual compensation.  We also sponsor a qualified 401 (k) Plan which provides for matching.  The cost to us under these plans for the three months ended December 31, 2009 and 2008 was $1.6 million for profit sharing and $0.1 million for the 401 (k) Plan and $0.5 million for profit sharing and $0.1 million for the 401 (k) Plan, respectively.  The cost to us under these plans for the six months ended December 31, 2009 and 2008 was $1.9 million for profit sharing and $0.6 million for the 401 (k) Plan and $1.0 million for profit sharing and $0.7 million for the 401 (k) Plan, respectively.

Note 12 – Stockholders’ Equity

Common Stock

At the Company’s 2009 Annual General Meeting of Shareholders (AGM) held on December 11, 2009, the 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 the Board of Directors. In January 2010, the Board of Directors approved a 1:5 stock consolidation or reverse stock split effective January 29, 2010.

The shareholders also voted to increase the authorized capital of the Company 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.

Our common stock trades on NASDAQ and on the London Stock Exchange Alternative Investment Market (“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.

- 19 -

On December 14, 2009, the Company closed on an offering of 18,000,000 shares of $.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.

Net proceeds to the Company for the combined common stock offerings, after deducting $0.50 per share underwriters’ commissions and offering costs were $188.0 million.

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.

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

Dividends on the Convertible Preferred Stock are payable quarterly in arrears on each March 15, June 15, September 15 and December 15 of each year commencing on March 15, 2010.

Dividends on the Convertible 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 Convertible 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 Convertible 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).

Warrants

As of June 30, 2009, we had 2,595,483 outstanding warrants exercisable for $25 per share which expired on October 20, 2009.

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 would each be convertible into a share of our common stock at $25.00 per share with an expiration date of 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 Units expire on October 20, 2010; however, the warrants contained in each Unit expired on October 20, 2009. There were no unit purchase options exercised at December 31, 2009.

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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 the potential dilution that would occur if warrants to issue common stock were exercised.  The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

	Three Months Ended					Six Months Ended
	December 31,					December 31,
	2009		2008			2009		2008
Net Income (Loss)	$	16,446	$	(429,203	)	$	4,146	$	(433,854	)
Preferred Stock Dividends		332		—			332		—
Net Income (Loss) Available for Common Stockholders	$	16,114	$	(429,203	)	$	3,814	$	(433,854	)
Weighted average shares outstanding for basic EPS		33,788		28,835			31,470		28,896
Add dilutive securities		2,027		—			1,157		—
Weighted average shares outstanding for diluted EPS		35,815		28,835			32,627		28,896
Earnings (Loss) Per Share
Basic	$	0.48	$	(14.88	)	$	0.12	$	(15.01	)
Diluted	$	0.46	$	(14.88	)	$	0.13	$	(15.01	)

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 December 31, 2009 under the operating leases are as follows (in thousands):

Twelve Months Ending December 31,
2010	$	1,351
2011		1,351
2012		1,351
2013		1,351
2014		1,351
Thereafter		4,371
Total	$	11,126

Rent expense for the three months and six months ended December 31, 2009 and 2008 was approximately $752,000 and $499,000 and $1,136,000 and $1,046,000, respectively.

Letters of Credit and Performance Bonds. We had $33.8 million in letters of credit and $122.2 million of performance bonds outstanding as of December 31, 2009.

Drilling Rig Commitments.  We have entered into two drilling rig commitments, one commencing on December 15, 2009 at $29,000 per day which was released on January 6, 2010 for a total commitment of $638,000 and the other at $27,250 per day until well completion. The last commitment extends past December 31, 2009, thus, the commitment amount cannot be calculated since the well completion date is not known.

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Note 15 — Fair Value of Financial Instruments

 On July 1, 2008, we adopted the authoritative guidance that applies to all financial and non-financial assets and liabilities required to be measured and reported at fair value, and also requires that a company’s own credit risk be considered in determining the fair value of those instruments. The adoption of this authoritative guidance resulted in a $10 million pre-tax increase in other comprehensive income and a $10 million reduction of our liabilities to reflect the consideration of our credit risk on our liabilities that are recorded at fair value.

 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. For our interest rate derivatives, the fair value may be calculated based on these inputs as well as third-party estimates of these instruments. We separate our financial instruments and other derivatives into two levels (Levels 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. 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 between levels. Each of these levels and our corresponding instruments classified by level are further 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.

• Level 3 instruments’ fair values are based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our valuation models are industry-standard and consider various inputs including third party broker-quoted forward amounts and time value of money.

            Listed below are our financial instruments classified in each level and a description of the significant inputs utilized to determine their fair value at December 31, 2009 (in thousands):

	Level 2		Level 3		Total
Assets:
Natural Gas and Oil Derivatives	$	31,002			$	31,002
Liabilities:
Natural Gas and Oil Derivatives	$	20,057			$	20,057
Interest Rate Collar			$	1,952		1,952
Total Liabilities	$	20,057	$	1,952	$	22,009

The following table sets forth a reconciliation of changes in the fair value of derivatives classified as Level 3 (in thousands):

	Interest Rate Collar
Balance at July 1, 2009	$	3,474
Total loss included in other comprehensive income		406
Settlements		(1,928	)
Balance at December 31, 2009	$	1,952

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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):

	December 31, 2009		June 30, 2009
Prepaid expenses and other current assets
Advances to joint interest partners	$	17,366	$	7,858
Insurance		13,312		168
Inventory		5,526		5,526
Other		1,407		2,766
Total prepaid expenses and other current assets	$	37,611	$	16,318
Accrued liabilities
Advances from joint interest partners	$	2,907	$	338
Employee benefits and payroll		12,900		8,096
Interest		4,804		4,855
Accrued hedge revenue		9,562		8,179
Undistributed oil and gas proceeds		11,796		11,744
Other		1,702		2,968
Total accrued liabilities	$	43,671	$	36,180

Note 17 – Supplemental Cash Flow Information

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

	Six Months Ended December 31,
	2009		2008
Cash paid for interest	$	41,463	$	38,671

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

	Six Months Ended December 31,
	2009			2008
Additions to property and equipment by recognizing accrued payables	$	14,600		$	(3,481	)
Financing of insurance premiums		6,549			7,886
Imputed interest expense on Mit Acquisition		(1,133	)		—
Additions to property and equipment by recognizing asset retirement obligations		1,683			3,309
Preferred stock dividends		332			—

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

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q and with our Annual Report on Form 10-K for the year ended June 30, 2009 (“the 2009 Annual Report”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report.  The following discussion includes forward looking statements that reflect our plans, estimates and beliefs.  Our actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to those discussed under “Item 1A Risk Factors.”

General

            We are an independent oil and natural gas exploration and production company whose growth strategy emphasizes acquisitions of oil and natural gas properties, enhanced by our value-added organic drilling program. Our properties are primarily located in the U.S. Gulf of Mexico waters and the Gulf Coast onshore. We were originally formed in July 2005 as an exempted company under the laws of Bermuda to serve as a vehicle for the acquisition of oil and natural gas reserves and related assets. In October 2005, we completed a $300 million initial public offering of common stock and warrants on the AIM of the London Stock Exchange. To date, we have completed three major acquisitions of oil and natural gas properties and have listed our common stock on the NASDAQ Capital Market.

We operate geographically focused producing reserves and target the acquisition of oil and natural 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.

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Operational Information

	Dec. 31, 2009			Sept. 30, 2009			June 30, 2009			Mar. 31, 2009			Dec. 31, 2008
Operating revenues
Crude oil sales	$	93,974		$	58,114		$	58,920		$	46,492		$	53,388
Natural gas sales		16,812			9,770			15,168			20,435			33,111
Hedge gain		13,720			17,023			27,010			39,209			20,353
Total revenues		124,506			84,907			101,098			106,136			106,852
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		84.8	%		85.6	%		79.5	%		69.5	%		61.7	%
Including hedge gain (loss)		78.8			78.1	%		70.8	%		68.3	%		62.4	%
Operating expenses
Lease operating expense
Insurance expense		7,827			5,954			4,356			4,980			4,934
Workover and maintenance		2,678			3,231			4,622			341			7,094
Direct lease operating expense		24,545			16,240			15,646			19,643			25,536
Total lease operating expense		35,050			25,425			24,624			24,964			37,564
Production taxes		1,007			1,275			(51	)		1,587			1,878
Impairment of oil and gas properties		—			—			—			117,887			459,109
Depreciation, depletion and amortization (“DD&A”)		44,972			35,351			39,744			50,052			65,002
General and administrative		14,022			8,066			6,168			6,117			6,236
Other – net		8,116			(1,133	)		3,852			7,643			(7,604	)
Total operating expenses		103,167			68,984			74,337			208,250			562,185
Operating income (loss)	$	21,339		$	15,923		$	26,761		$	(102,114	)	$	(455,333	)
Sales volumes per day
Natural gas (MMcf)		40.7			33.2			41.1			49.2			54.4
Crude oil (MBbls)		14.2			10.0			11.9			12.5			10.1
Total (MBOE)		20.9			15.5			18.7			20.7			19.2
Percent of sales volumes from crude oil		67.6	%		64.5	%		63.6	%		60.4	%		52.7	%
Average sales price
Natural gas per Mcf	$	4.49		$	3.20		$	4.06		$	4.62		$	6.62
Hedge gain per Mcf		2.58			2.90			3.85			2.98			1.41
Total natural gas per Mcf	$	7.07		$	6.10		$	7.91		$	7.60		$	8.03
Crude oil per Bbl	$	72.17		$	63.44		$	54.56		$	41.40		$	57.38
Hedge gain per Bbl		3.13			8.93			11.68			23.16			14.27
Total crude oil per Bbl	$	75.30		$	72.37		$	66.24		$	64.56		$	71.65
Total hedge gain per BOE	$	7.12		$	11.95		$	15.86		$	21.07		$	11.54
Operating revenues per BOE	$	64.65		$	59.59		$	59.36		$	57.04		$	60.57
Operating expenses per BOE
Lease operating expense
Insurance expense		4.06			4.18			2.56			2.68			2.79
Workover and maintenance		1.39			2.27			2.71			0.18			4.02
Direct lease operating expense		12.74			11.40			9.19			10.56			14.48
Total lease operating expense		18.19			17.85			14.46			13.42			21.29
Production taxes		0.52			0.89			(0.03	)		0.85			1.06
Impairment of oil and gas properties		—			—			—			63.35			260.26
DD&A		23.35			24.81			23.34			26.90			36.85
General and administrative		7.28			5.66			3.62			3.29			3.54
Other – net		4.22			(0.80	)		2.27			4.11			(4.31	)
Total operating expenses		53.56			48.41			43.66			111.92			318.69
Operating income (loss) per BOE	$	11.09		$	11.18		$	15.70		$	(54.88	)	$	(258.12	)

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Results of Operations

Three Months Ended December 31, 2009 Compared With the Three Months Ended December 31, 2008.

Our consolidated net income for the three months ended December 31, 2009 was $16.4 million or $0.46 diluted earnings per common share (“per share”) as compared to consolidated net loss of $429.2 million or $14.88 diluted loss per share for the three months ended December 31, 2008. The increase is primarily due to the impairment of oil and gas properties incurred in the prior fiscal year quarter coupled with higher production volumes and higher commodity prices in the current fiscal year quarter.

Price and Volume Variances

	Three Months Ended									Percent			Revenue
	December 31,						Increase			Increase			Increase
	2009			2008			(Decrease)			(Decrease)			(Decrease)
													(In thousands)
Price Variance (1)
Crude oil sales prices (per Bbl)	$	75.30		$	71.65		$	3.65			5.1	%	$	4,752
Natural gas sales prices (per Mcf)		7.07			8.03			(0.96	)		(12.0	)%		(3,593	)
Total price variance														1,159
Volume Variance
Crude oil sales volumes (MBbls)		1,302			930			372			40.0	%		26,630
Natural gas sales volumes (MMcf)		3,743			5,002			(1,259	)		(25.2	)%		(10,135	)
BOE sales volumes (MBOE)		1,926			1,764			162			9.2	%
Percent of BOE from crude oil		67.6	%		52.7	%
Total volume variance														16,495
Total price and volume variance													$	17,654

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

Revenue Variances

	Three Months Ended December 31,
	2009		2008		Increase (Decrease)			Percent Increase (Decrease)
	(In Thousands)
Crude oil	$	98,050	$	66,668	$	31,382			47.1	%
Natural gas		26,456		40,184		(13,728	)		(34.2	)%
Total revenues	$	124,506	$	106,852	$	17,654			16.5	%

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Revenues

Our consolidated revenues increased $17.7 million in the second quarter of fiscal 2010 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher crude oil production volumes which were partially offset by lower natural gas production volumes.  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 improved revenues by $1.2 million in the second quarter of fiscal 2010. Average natural gas prices, including a $2.58 realized gain per Mcf related to hedging activities, decreased $0.96 per Mcf during the second quarter of fiscal 2010, resulting in decreased revenues of $3.6 million. Average crude oil prices, including a $3.13 realized gain per barrel related to hedging activities, increased $3.65 per barrel in the second quarter of fiscal 2010, resulting in increased revenues of $4.8 million.  Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during the second quarter of fiscal 2010 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 sales volumes in the second quarter of fiscal 2010 resulted in increased revenues of $16.5 million. Crude oil sales volumes increased 4.1 MBbls per day in the second quarter of fiscal 2010, resulting in increased revenues of $26.6 million. Natural gas sales volumes decreased 13.7 MMcf per day in the second quarter of fiscal 2010, resulting in decreased revenues of $10.1 million.  The increase in crude oil sales volumes in the second quarter of fiscal 2010 was primarily due to the Mit Acquisition.  The decrease in natural gas sales volumes in the second quarter of fiscal 2010 was primarily due to the impact of temporary shut-ins caused by third-part pipeline outages and dredging operations conducted by the U.S. Corps of Engineers.

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 December 31,												Increase
	2009						2008						(Decrease)
	Amount			Per BOE			Amount			Per BOE			Amount
Costs and expenses	(In Thousands, except per unit amounts)
Lease operating expense
Insurance expense	$	7,827		$	4.06		$	4,934		$	2.79		$	2,893
Workover and maintenance		2,678			1.39			7,094			4.02			(4,416	)
Direct lease operating expense		24,545			12.74			25,536			14.48			(991	)
Total lease operating expense		35,050			18.19			37,564			21.29			(2,514	)
Production taxes		1,007			0.52			1,878			1.06			(871	)
Impairment of oil and gas properties		—			—			459,109			260.26			(459,109	)
DD&A		44,972			23.35			65,002			36.85			(20,030	)
Accretion of asset retirement obligation		6,160			3.20			2,433			1.38			3,727
General and administrative expense		14,022			7.28			6,236			3.54			7,786
Loss (gain) on derivative financial instruments		1,956			1.02			(10,037	)		(5.69	)		11,993
Total costs and expenses	$	103,167		$	53.56		$	562,185		$	318.69		$	(459,018	)
Other (income) expense
Other income	$	(27,658	)	$	(14.36	)	$	(2,104	)	$	(1.19	)	$	(25,554	)
Interest expense		24,345			12.64			21,168			12.00			3,177
Total other (income) expense	$	(3,313	)	$	(1.72	)	$	19,064		$	10.81		$	(22,377	)

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Costs and expenses decreased $459.0 million in the second quarter of fiscal 2010.  This decrease in costs and expenses was primarily due to the second quarter of fiscal 2010 impairment of oil and gas properties. Below is a discussion of other costs and expenses.

DD&A expense decreased $20.0 million primarily due to a lower DD&A rate ($26.0 million).  The lower DD&A rate was due to the impairment of oil and gas properties.  The decrease as a result of the lower DD&A rate was partially offset by increased production ($6.0 million).  Lease operating expense decreased $2.5 million in the second quarter of fiscal 2010 compared to the second quarter of fiscal 2009.  This decrease is primarily due to higher workover and maintenance costs in the second quarter of fiscal 2009 as a result of Hurricanes Gustav and Ike partially offset by higher well insurance expense as a result of higher insurance rates and the Mit acquisition in the second quarter of fiscal 2010.

 General and administrative expense increased $7.8 million in the second quarter of fiscal 2010 principally as a result of the bond exchange offer and higher employee stock option expense due to our rising common stock price.

Other (income) expense increased $22.4 million in the second quarter of fiscal 2010.  This increase was primarily due to the items discussed below.

Other income increased $25.6 million due principally to the gain related to the repurchased $126 million of New Notes. (See Note 6)  Interest expense increased $3.2 million due to an increase in the overall interest rates partially offset by a decrease in borrowings.  On a per unit of production basis, interest expense increased 5.3 percent, from $12.00/BOE to $12.64/BOE.

Income Tax Expense

Income tax expense increased $53.4 million in the second quarter of fiscal 2010 compared to the second quarter of fiscal 2009, primarily due to an increase in income before income taxes of $499.0 million and the establishment of a valuation allowance against the net deferred tax assets in the U.S.  The effective income tax rate for the second quarter of fiscal 2010 increased from the second quarter of fiscal 2009 from (9.5) percent to 33.2 percent.

Six Months Ended December 31, 2009 Compared with the Six Months Ended December 31, 2008.

Our consolidated net income was $4.1 million or $0.13 diluted earnings per share for the first six months of fiscal 2010 as compared to a consolidated net loss of $433.9 million or $15.01 diluted loss per share for the same prior year period.  The increase is primarily due to the impairment of oil and gas properties incurred in the prior fiscal year period partially offset with lower commodity prices in the current fiscal year period. Below is a discussion of prices, volumes and revenue variances.

Sales Price and Volume Variances

	Six Months Ended									Percent			Revenue
	December 31,						Increase			Increase			Increase
	2009			2008			(Decrease			(Decrease)			(Decrease)
													(In Thousands)
Price Variance (1)
Crude oil price (per Bbl)	$	74.08		$	76.55		$	(2.47	)		(3.2	)%	$	(5,478	)
Natural gas price (per Mcf)		6.63			8.36			(1.73	)		(20.7	)%		(11,755	)
Total price variance														(17,233	)
Volume Variance
Crude oil sales volumes (MBbls)		2,218			1,943			275			14.2	%		21,091
Natural gas sales volumes (MMcf)		6,795			9,306			(2,511	)		(27.0	)%		(21,041	)
BOE sales volumes MBOE		3,351			3,494			(143	)		(4.1	)%
Percent of BOE from crude oil		66.2	%		55.6	%
Total volume variance														50
Total price and volume variance													$	(17,183	)

(1)  Commodity prices include hedging gains and losses.

- 28 -

Revenue Variances

	Six Months Ended							Percent
	December 31				Increase			Increase
	2008		2007		(Decrease)			(Decrease)
	(In Thousands)
Crude oil	$	164,343	$	148,730	$	15,613			10.5	%
Natural gas		45,070		77,866		(32,796	)		(42.1	)%
Total revenues	$	209,413	$	226,596	$	(17,183	)		(7.6	)%

Revenues

Our consolidated revenues decreased $17.2 million in the first six months of fiscal 2010 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower commodity prices which reduced revenues by $17.2 million.  Operating revenues were also impacted by lower natural gas production volumes which decreased revenues by $21.0 million which was essentially offset by higher crude oil production volumes resulting in increased revenues of $21.1 million. 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.  Lower commodity prices contributed a net decrease of $17.2 million in revenues in the first six months of fiscal 2010 as compared to the prior year period.  Average crude oil prices, including a $5.52 realized gain per barrel related to hedging activities, decreased $2.47 per barrel in the first six months of fiscal 2010, resulting in decreased revenues of $5.5 million.  Average natural gas prices, including a $2.72 realized gain per Mcf related to hedging activities, decreased $1.73 per Mcf in the first six months of fiscal 2010, resulting in decreased revenues of $11.7 million.  Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received in the first six months of fiscal 2010 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time would 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.  BOE sales volumes in the first six months of fiscal 2010 were essentially the same as compared to the prior year period. Crude oil sales volumes increased 1.5 MBbls per day in the first six months of fiscal 2010, resulting in increased revenues of $21.1 million. Natural gas sales volumes decreased 13.7 MMcf per day in the first six months of fiscal 2010, resulting in lower revenues of $21.0 million.  The increase in crude oil sales volumes in the first six months of fiscal 2010 as compared to prior fiscal year’s first six months was primarily due to the Mit Acquisition.  The decrease in natural gas sales volumes in the first six months of fiscal 2010 as compared to prior fiscal year’s first six months was primarily due to the impact of temporary shut-ins caused by third-part pipeline outages and dredging operations conducted by the U.S. Corps of Engineers.

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.

- 29 -

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

 Costs and Expenses and Other (Income) Expense

	Six Months Ended December 31,												Increase
	2009						2008						(Decrease)
	Amount			Per BOE			Amount			Per BOE			Amount
Costs and expenses	(In Thousands, except per unit amounts)
Lease operating expense
Insurance expense	$	13,781		$	4.11		$	9,852		$	2.82		$	3,929
Workover and maintenance		5,909			1.76			10,967			3.14			(5,058	)
Direct lease operating expense		40,785			12.17			51,743			14.81			(10,958	)
Total lease operating expense		60,475			18.04			72,562			20.77			(12,087	)
Production taxes		2,282			0.68			3,914			1.12			(1,632	)
Impairment of oil and gas properties		—			—			459,109			131.41			(459,109	)
DD&A		80,323			23.97			127,411			36.47			(47,088	)
Accretion of asset retirement obligation		11,306			3.37			4,894			1.40			6,412
General and administrative expense		22,088			6.59			12,471			3.57			9,617
Loss (gain) on derivative financial instruments		(4,323	)		(1.29	)		(11,901	)		(3.41	)		7,578
Total costs and expenses	$	172,151		$	51.36		$	668,460		$	191.33		$	(496,309	)
Other (income) expense
Other income	$	(29,644	)	$	(8.85	)	$	(3,438	)	$	(0.98	)	$	(26,206	)
Interest expense		45,307			13.52			43,473			12.44			1,834
Total other (income) expense	$	15,663		$	4.67		$	40,035		$	11.46		$	(24,372	)

Costs and expenses decreased $496.3 million in the first six months of fiscal 2010 as compared to the prior year period.  This decrease in costs and expenses was primarily due to the first six months of fiscal 2009 impairment of oil and gas properties coupled by the net effect of the items discussed below.

DD&A expense decreased $47.1 million in the first six months of fiscal 2010 as compared to the prior year period primarily due to a lower DD&A rate ($41.9 million).  The lower DD&A rate was due to the impairment of oil and gas properties in the prior year’s period.  The lower production decreased DD&A expense by $5.2 million.  Lease operating expense decreased $12.1 million in the first six months of fiscal 2010 compared to first six months of fiscal 2009.  This decrease is primarily due to higher workover and maintenance costs in the first six months of fiscal 2009 as a result of Hurricanes Gustav and Ike partially offset by higher well insurance expense as a result of higher insurance rates and the Mit Acquisition.

Other (income) expense increased $24.4 million in the first six months of fiscal 2010 as compared to the prior year period.  This increase was primarily due to the items discussed below.

Other income increased $26.2 million due to the gain related to the repurchased $126 million of New Notes. (See Note 6)  Interest expense increased $1.8 million due to an increase in the overall interest rates partially offset by a decrease in borrowings.   On a per unit of production basis, interest expense increased 8.7 percent, from $12.44/BOE to $13.52/BOE.

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Income Tax Expense

Income tax expense decreased $65.5 million in the first six months of fiscal 2010 compared to the first six months of fiscal 2009, primarily due to an increase in income before income taxes of $503.5 million, and the establishment of a valuation allowance against the net deferred tax assets in the U.S. The effective income tax rate for the first six months of fiscal 2010 increased from the first six months of fiscal 2009 from (10.0) percent to 80.8 percent.

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 owed during the period related to our hedging positions.

     During the six-months ended December 31, 2009, we have:

1)    Issued $278 million of 16% Second Lien Notes in exchange for $347.5 million of high yield New Notes

2)    Issued $60 million in 16% Second Lien Notes and 2.6 million shares of common stock for $60 million in cash

3)    Issued 18.8 million shares of common stock and 1.1 million shares of 7.25% non-redeemable, perpetual, convertible preferred stock

4)    Acquired certain Gulf of Mexico shelf oil and gas properties for $273.1 million in cash

5)    In February 2010, we expect to amend our First Lien Revolver extending the maturity to February 2013

The December 31, 2009 principal balance of our First Lien Revolver, High Yield New Notes and 16% Second Lien Notes and related maturity dates (after consideration for the expected February 2010 amendment to our First Lien Revolver) are as follows:

1)    First Lien Revolver - $149.1 million – Due February 2013

2)    High Yield Notes - $276.5 million – Due June 2013

3)    16% Second Lien Notes - $338.6 million – Due June 2014

In October 2009, we procured bonding in the amount of approximately $98 million to meet the supplemental bonding requirements of the U.S. Minerals Management Services (“MMS”) to comply with MMS regulations governing, among other things, plugging and abandonment of wells on the outer continental shelf of the Gulf of Mexico and the removal of facilities.  In order to procure such bonding, we issued letters of credit and or cash deposits of approximately $27.8 million to secure the bonds and have ongoing collateral requirements.  As of December 31, 2009, we had $30.0 million in letters of credit supporting such bonds.

Although subject to MMS review and approval, the Company believes it will meet the financial requirements to be exempt from MMS bonding requirements as of December 31, 2009 and will be pursuing the release of our bonds during the quarter ended March 31, 2010.

Capital Resources

Our fiscal 2010 capital budget, excluding acquisitions, abandonment costs and reimbursable hurricane-related spending is expected to be approximately $110 million. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, and future acquisitions from cash on hand, cash flows from our operations and, when available, borrowings under our credit facility. Notwithstanding the continued weakness in credit markets, we believe our available liquidity will be sufficient to meet our funding requirements through December 31, 2010.  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 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 six months of fiscal 2010.  At December 31, 2009 we had a working capital deficit of $56.2 million.

We anticipate that our operations, which will include the Mit Acquisition, will provide sufficient cash to maintain our planned capital expenditure levels.  As discussed in Note 6, in February 2010, we expect to amend our First Lien Revolver with an increase in the borrowing base to $350 million.

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Net cash used by operating activities in the first six months of fiscal 2010 was $37.7 million as compared to $95.5 million provided by operating activities in the first six months of fiscal 2009.  The decrease is due in part to lower commodity prices.  Key drivers of net operating cash flows are commodity prices, production volumes and costs and expenses. Average natural gas prices decreased 20.7 percent in the first six months of fiscal 2010 from the same period last year. Crude oil prices decreased 3.2 percent in the first six months of fiscal 2010 from the same period last year.   Changes in operating assets and liabilities decreased $104.3 million primarily due to asset retirement obligations and insurance related accounts receivable.

Contractual Obligations

Information about contractual obligations at December 31, 2009 did not change materially, other than as disclosed  in Note 14, from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended June 30, 2009.

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended June 30, 2009.  Also refer to the Notes to Consolidated Financial Statements included in Part 1, Item 1 of this report.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Item 1. Financial Statements – Note 2 – Recent Accounting Pronouncements.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Market-Sensitive Instruments and Risk Management

Market risk is the potential loss arising from adverse changes in market rates and prices, such as commodity prices and interest rates. Our primary market risk exposure is commodity price risk. The exposure is discussed in detail below:

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.

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.  Based on the December 31, 2009 published forward commodity price curves for the underlying commodities, a price increase of 10 percent per barrel for crude oil would decrease the fair value of our net commodity derivative asset by approximately $13.1 million. A price increase of 10 percent per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $24.3 million.

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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.

Disclosure of Limitations

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.

          Interest Rate Risk

On June 26, 2006, we entered into interest rate costless collar to mitigate the risk of loss due to changes in interest rates. The dollar amount hedged was $75 million with the interest rate collar being 5.45 percent to 5.75 percent. At December 31, 2009, the fair value of this instrument which was designated as a financial hedge, prior to the impact of federal income tax, was a loss of $1.9 million.

 A one percent increase in interest rates would increase our interest expense approximately $0.75 million for the remainder of fiscal 2010.

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

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 its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and Chief Financial Officer believe that the disclosure controls and procedures were effective as of the end of the period covered by this report with respect to timely communicating to them and other members of management responsible for preparing periodic reports all material information required to be disclosed in this report as it relates to our Company and its consolidated subsidiaries.

Our management does not expect that its disclosure controls and procedures or its internal control over financial reporting will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some person or by collusion of two or more people. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Accordingly, our disclosure controls and procedures are designed to provide reasonable, not absolute, assurance that the objectives of our disclosure control system are met and, as set forth above, our management has concluded, based on their evaluation as of the end of the period, that our disclosure controls and procedures were sufficiently effective to provide reasonable assurance that the objectives of our disclosure control system were met.

There was no change in our internal control over financial reporting during our last quarterly period ended December 31, 2009 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 affect on our financial position or results of operations.

ITEM 1A.                           Risk Factors

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended June 30, 2009. 

ITEM 2.                           Unregistered Sales of Equity Securities and Use of Proceeds

Purchases and Distributions of Equity Securities are as follow:

	Total Number		Average Price
Period	Of Shares		Per Share		Total
					(In thousands)
Purchases
Month Ended July 31, 2009		156,119	$	2.95	$	464
Distributions
Month Ended July 31, 2009		122,521	$	2.50	$	309
Month Ended August 31, 2009		52,422		3.30		174
Month Ended September 30, 2009		6,734		8.10		54
Month Ended October 31, 2009		27		8.60		-
Month Ended November 30, 2009		3,237		11.95		39
Month Ended December 31, 2009		8,408		9.50		80
Total Distributions		193,379	$	3.40	$	656

The distributions of shares relate to satisfaction of amounts due to employees under various employee compensations plans.

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ITEM 4.      Submission of Matters to a Vote of Security Holders

Energy XXI’s Annual General Meeting of Shareholders was held on December 11, 2009 for the purposes of (1) electing two directors as Class I directors, each for a three-year term, (2) approving amendments to our 2006 Long-Term Incentive Plan, including an amendment to increase the number of our Common Shares available for awards to 3,800,000, (3) approving an amendment to our Memorandum of Association to increase the total number of Common Shares that the Company has authority to issue from 80,000,000 to 200,000,000 Common Shares and approve an amendment to our Bye-Laws to reflect the increase, (4) authorizing our Board of Directors to effect a share consolidation or reverse stock split of our Common Shares at any time on or before December 31, 2010 at one of five reverse split ratios, 1 for 2, 1 for 5, 1 for 10, 1 for 15 and 1 for 20, as determined by our Board of Directors in its sole discretion, and if and when the reverse stock split is effected, reduce the number of our authorized Common Shares by the reverse split ratio determined by our Board of Directors to apply equally to our authorized Common Shares, (5) authorizing our Board of Directors, at its discretion, to effect a cancellation of the admission of our Common Shares to AIM, to be effective any time on or before March 11, 2010, and (6) ratifying and approving the audit committee’s appointment of UHY LLP as our independent auditors for our fiscal year ending June 30, 2010 and authorizing the audit committee to set the auditor’s remuneration for our fiscal year ending June 30, 2010.

At the record date of November 13, 2009, 31,966,019 shares of common stock were outstanding and entitled to one vote per share upon all matter submitted at the meeting.  Holders of 22,864,809 shares of common stock, representing approximately 71.53% of the total issued and outstanding shares of common stock, were present in person or by proxy at the meeting to cast their vote. 

             With respect to the elections of directors, both nominees were re-elected.  The votes were cast as follow:

Nominees for Directors	Votes For	Votes Withheld
Paul Davison (Class I)	23,339,155	525,654
Hill A. Feinberg (Class I)	22,288,559	576,250

Mr. David West Griffin chose not to stand for re-election to concentrate on his duties as chief financial officer of the Company.    

The proposal to approve amendments to our 2006 Long-Term Incentive Plan, including an amendment to increase the number of our Common Shares available for awards to 3,800,000, was approved.  The votes were cast as follows:

For	Against	Abstentions
12,875,879	746,967	9,241,961

The proposal to approve an amendment to our Memorandum of Association to increase the total number of Common Shares that the Company has authority to issue from 80,000,000 to 200,000,000 Common Shares and approve an amendment to our Bye-Laws to reflect the increase was approved.  The votes were cast as follows:

For	Against	Abstentions
19,040,744	3,383,045	41,020

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The proposal to approve authorizing our Board of Directors to effect a share consolidation or reverse stock split of our Common Shares at any time on or before December 31, 2010 at one of five reverse split ratios, 1 for 2, 1 for 5, 1 for 10, 1 for 15 and 1 for 20, as determined by our Board of Directors in its sole discretion, and if and when the reverse stock split is effected, reduce the number of our authorized Common Shares by the reverse split ratio determined by our Board of Directors to apply equally to our authorized Common Shares, was approved.  The votes were cast as follows:

For	Against	Abstentions
21,795,642	1,053,441	15,725

The proposal to approve authorizing our Board of Directors, at its discretion, to effect a cancellation of the admission of our Common Shares to AIM, to be effective any time on or before March 11, 2010, was approved.  The votes were cast as follows:

For	Against	Abstentions
22,325,738	382,470	156,601

The proposal ratifying and approving the audit committee’s appointment of UHY LLP as our independent auditors for our fiscal year ending June 30, 2010 and authorizing the audit committee to set the auditor’s remuneration for our fiscal year ending June 30, 2010 was approved.  The votes were cast as follows:

For	Against	Abstentions
22,,699,591	140,202	25,023

ITEM 6.                      Exhibits

The following exhibits are filed as part of this report.

Exhibit
Number	Description
31.1	Rule 13a-14(a)/15d-14(a) Certification of the Chairman and Chief Executive Officer Under Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer Under Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Section 1350 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Section 1350 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ENERGY XXI (BERMUDA) LIMITED
By	/S/ DAVID WEST GRIFFIN
	David West Griffin
	Chief Financial Officer
By	/S/ HUGH A. MENOWN
	Hugh A. Menown
	Vice President, Chief Accounting Officer and Chief Information Officer

Date:   February 3, 2010

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