10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-Q

 

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

For the quarterly period ended March 31, 2013

OR

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

For the transition period from             to            

Commission File Number: 001-33628

 

ENERGY XXI (BERMUDA) LIMITED

(Exact name of registrant as specified in its charter)

 

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

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

(441) 295-2244

(Registrant's telephone number, including area code)

 

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 þ No o

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

Large accelerated filer þ	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of April 26, 2013, there were 79,374,772 shares outstanding of the registrant’s common stock, par value $0.005 per share.

ENERGY XXI (BERMUDA) LIMITED
TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS		1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		4
PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements		5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		42
ITEM 4. Controls and Procedures		43
PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings		45
ITEM 1A. Risk Factors		45
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		45
ITEM 3. Defaults upon Senior Securities		45
ITEM 4. Mine Safety Disclosures		45
ITEM 5. Other Information		45
ITEM 6. Exhibits		45
SIGNATURES		46
EXHIBIT INDEX		47

i

GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this Quarterly Report on Form 10-Q:

Bbls	Standard barrel containing 42 U.S. gallons	MMBbls	One million Bbls
Mcf	One thousand cubic feet	MMcf	One million cubic feet
Btu	One British thermal unit	MMBtu	One million Btu
BOE	Barrel of oil equivalent. Natural gas is converted into one BOE based on six Mcf of gas to one barrel of oil	MBOE	One thousand BOEs
DD&A	Depreciation, Depletion and Amortization	MMBOE	One million BOEs
MBbls	One thousand Bbls

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

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

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

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For a complete definition of proved developed oil and gas reserves, refer to Rule 4-10(a) (3) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

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

Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploitation is drilling wells in areas proven to be productive.

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

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

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4-10(a) (8) of Regulation S-X as promulgated by the SEC.

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

1

Gathering and transportation is the cost of moving crude oil from several wells into a single tank battery or major pipeline.

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

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

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

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

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

Oil includes crude oil, condensate and natural gas liquids.

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

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

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

Productive well is an exploratory, development or extension well that is not a dry well.

Proved area refers to the part of a property to which proved reserves have been specifically attributed.

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

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

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

Reservoir refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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

Stratigraphic test well refers to a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types

2

of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.

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

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

Zone is a stratigraphic interval containing one or more reservoirs.

3

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

• our business strategy;

• our financial position;

• the extent to which we are leveraged;

• our cash flow and liquidity;

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

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

• uncertainties in estimating our oil and gas reserves;

• replacing our oil and gas reserves;

• uncertainties in exploring for and producing oil and gas;

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

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

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

• availability, cost and adequacy of insurance coverage;

• competition in the oil and gas industry;

• our inability to retain and attract key personnel;

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

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

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, “Item 1A. Risk Factors” and elsewhere in this Quarterly Report and (2) Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2012 (the “2012 Annual Report”).

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

4

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

	March 31, 2013			June 30, 2012
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	30,229		$	117,087
Accounts receivable
Oil and natural gas sales		138,522			126,107
Joint interest billings		9,260			3,840
Insurance and other		4,773			5,420
Prepaid expenses and other current assets		22,794			63,029
Derivative financial instruments		23,900			32,497
Total Current Assets		229,478			347,980
Property and Equipment
Oil and natural gas properties – full cost method of accounting, including $539.4 million and $418.8 million of unevaluated properties not being amortized at March 31, 2013 and June 30, 2012, respectively		3,148,239			2,698,213
Other property and equipment		16,114			9,533
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		3,164,353			2,707,746
Other Assets
Derivative financial instruments		17,134			45,496
Debt issuance costs, net of accumulated amortization		29,599			27,608
Equity method investments		13,408			2,117
Total Other Assets		60,141			75,221
Total Assets	$	3,453,972		$	3,130,947
LIABILITIES
Current Liabilities
Accounts payable	$	172,017		$	156,959
Accrued liabilities		121,564			118,818
Notes payable		1,080			22,211
Asset retirement obligations		30,130			34,457
Derivative financial instruments		112			—
Current maturities of long-term debt		23,428			4,284
Total Current Liabilities		348,331			336,729
Long-term debt, less current maturities		1,227,144			1,014,060
Deferred income taxes		139,268			104,280
Asset retirement obligations		283,317			266,958
Derivative financial instruments		561			—
Other liabilities		9,220			3,080
Total Liabilities		2,007,841			1,725,107
Commitments and Contingencies (Note 16)
Stockholders’ Equity
Preferred stock, $0.001 par value, 7,500,000 shares authorized at March 31, 2013 and June 30, 2012, respectively
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at March 31, 2013 and June 30, 2012, respectively		—			—
5.625% Convertible perpetual preferred stock, 813,188 and 814,117 shares issued and outstanding at March 31, 2013 and June 30, 2012, respectively		1			1
Common stock, $0.005 par value, 200,000,000 shares authorized and 79,373,500 and 79,147,340 shares issued and 79,372,837 and 78,837,697 shares outstanding at March 31, 2013 and June 30, 2012, respectively		397			396
Additional paid-in capital		1,510,811			1,501,785
Accumulated deficit		(79,199	)		(153,945	)
Accumulated other comprehensive income, net of income tax expense		14,121			57,603
Total Stockholders’ Equity		1,446,131			1,405,840
Total Liabilities and Stockholders’ Equity	$	3,453,972		$	3,130,947

 
 
See accompanying Notes to Consolidated Financial Statements

5

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, except per share information)
(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012
Revenues
Oil sales	$	274,364		$	312,714		$	807,518		$	868,978
Natural gas sales		29,410			23,282			87,002			92,479
Total Revenues		303,774			335,996			894,520			961,457
Costs and Expenses
Lease operating		86,305			78,447			254,708			223,614
Production taxes		1,352			1,499			3,765			4,847
Gathering and transportation		4,411			2,465			18,500			12,013
Depreciation, depletion and amortization		88,727			88,448			279,378			260,819
Accretion of asset retirement obligations		7,649			9,762			23,057			29,253
General and administrative expense		16,092			25,075			59,299			66,543
(Gain) loss on derivative financial instruments		(632	)		3,495			5,755			(2,506	)
Total Costs and Expenses		203,904			209,191			644,462			594,583
Operating Income		99,870			126,805			250,058			366,874
Other Income (Expense)
Loss from equity method investees		(2,587	)		—			(4,698	)		—
Other income – net		523			97			1,425			121
Interest expense		(27,682	)		(26,887	)		(81,339	)		(82,438	)
Total Other Expense		(29,746	)		(26,790	)		(84,612	)		(82,317	)
Income Before Income Taxes		70,124			100,015			165,446			284,557
Income Tax Expense		29,688			8,763			65,418			29,885
Net Income		40,436			91,252			100,028			254,672
Induced Conversion of Preferred Stock		—			6,058			—			6,058
Preferred Stock Dividends		2,873			2,739			8,623			10,151
Net Income Available for Common Stockholders	$	37,563		$	82,455		$	91,405		$	238,463
Earnings Per Share
Basic	$	0.47		$	1.06		$	1.15		$	3.10
Diluted	$	0.46		$	1.04		$	1.14		$	2.92
Weighted Average Number of Common Shares Outstanding
Basic		79,365			77,454			79,280			76,803
Diluted		87,516			87,353			87,471			87,185

 
 
See accompanying Notes to Consolidated Financial Statements

6

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Thousands)
(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012
Net Income	$	40,436		$	91,252		$	100,028		$	254,672
Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		(2,010	)		(59,089	)		(38,393	)		106,915
Effective portion reclassified to earnings during the period		(7,165	)		(2,075	)		(28,502	)		(25,627	)
Total Other Comprehensive Income (Loss)		(9,175	)		(61,164	)		(66,895	)		81,288
Income Tax (Expense) Benefit		3,211			21,407			23,413			(28,451	)
Net Other Comprehensive Income (Loss)		(5,964	)		(39,757	)		(43,482	)		52,837
Comprehensive Income	$	34,472		$	51,495		$	56,546		$	307,509

 
 
See accompanying Notes to Consolidated Financial Statements

7

ENERGY XXI (BERMUDA) LIMITED
  
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012
Cash Flows From Operating Activities
Net income	$	40,436		$	91,252		$	100,028		$	254,672
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		88,727			88,448			279,378			260,819
Deferred income tax expense		25,625			8,764			58,439			30,036
Change in derivative financial instruments
Proceeds from derivative instruments		574			993			735			66,522
Other – net		(5,318	)		(10,866	)		(19,336	)		(36,557	)
Accretion of asset retirement obligations		7,649			9,762			23,057			29,253
Loss from equity method investees		2,587			—			4,698			—
Amortization and write-off of debt issuance costs		1,910			1,886			5,708			5,591
Stock-based compensation		483			478			2,139			10,592
Changes in operating assets and liabilities
Accounts receivable		(1,858	)		(9,565	)		(9,254	)		(27,146	)
Prepaid expenses and other current assets		19,541			9,945			40,263			4,879
Settlement of asset retirement obligations		(4,761	)		(4,569	)		(29,570	)		(6,563	)
Accounts payable and accrued liabilities		34,314			11,670			(4,740	)		(25,916	)
Net Cash Provided by Operating Activities		209,909			198,198			451,545			566,182
Cash Flows from Investing Activities
Acquisitions		(112,566	)		(35	)		(153,722	)		(6,212	)
Capital expenditures		(184,504	)		(155,744	)		(563,554	)		(394,188	)
Insurance payments received		—			—			—			6,472
Net contributions to equity investees		(503	)		—			(16,027	)		—
Proceeds from the sale of properties		—			203			—			2,970
Other		(409	)		1,252			(54	)		444
Net Cash Used in Investing Activities		(297,982	)		(154,324	)		(733,357	)		(390,514	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		499			191			5,259			9,647
Conversion of preferred stock to common		—			(6,029	)		—			(6,029	)
Dividends to shareholders – common		(5,556	)		—			(16,659	)		—
Dividends to shareholders – preferred		(2,873	)		(2,877	)		(8,623	)		(10,289	)
Proceeds from long-term debt		532,990			185,437			1,142,439			707,761
Payments on long-term debt		(447,653	)		(214,468	)		(928,914	)		(818,787	)
Other		—			—			1,452			(854	)
Net Cash Provided by (Used in) Financing Activities		77,407			(37,746	)		194,954			(118,551	)
Net Increase (Decrease) in Cash and Cash Equivalents		(10,666	)		6,128			(86,858	)		57,117
Cash and Cash Equivalents, beginning of period		40,895			79,396			117,087			28,407
Cash and Cash Equivalents, end of period	$	30,229		$	85,524		$	30,229		$	85,524

 
 
See accompanying Notes to Consolidated Financial Statements

8

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 — Basis of Presentation

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

References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

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

Interim Financial Statements.  The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended June 30, 2012 (the “2012 Annual Report”).

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

Note 2 — Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-05: Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. The update is intended to increase the prominence of other comprehensive income in the financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011, with early adoption permitted. We adopted ASU 2011-05 on June 30, 2012 and the adoption had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12: Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”). ASU 2011-12 defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. As part of this update, the FASB did not defer the requirement to report

9

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 2 — Recent Accounting Pronouncements  – (continued)

comprehensive income either in a single continuous statement or in two separate but consecutive financial statements. ASU 2011-12 is effective for annual periods beginning after December 15, 2011.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

In February 2013, the FASB issued Accounting Standards Update No. 2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of other comprehensive income (“AOCI”) included in equity in one place. Total changes in AOCI by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We do not expect the adoption ASU 2013-02 to have any effect on our consolidated financial position, results of operations or cash flows, other than presentation.

Note 3 — Acquisitions

ExxonMobil oil and gas properties interests acquisition

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“Exxon”) for a total cash consideration of approximately $33.5 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VM 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture agreement with Exxon to explore for oil and gas on nine contiguous blocks adjacent to VM 164 in shallow waters on the Gulf of Mexico shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012. Our total capital commitment for the joint venture in calendar year 2013 is estimated at $75 million, assuming successful completion of two earning wells.

Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income. The acquisition of the GOM interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	11,088
Oil and natural gas properties – unevaluated		27,721
Asset retirement obligations		(5,353	)
Cash paid	$	33,456

Dynamic Offshore oil and gas properties interests acquisition

On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VM 164 for approximately $7.2 million.

Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income. The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this

10

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 3 — Acquisitions  – (continued)

acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	1,716
Oil and natural gas properties – unevaluated		6,571
Asset retirement obligations		(1,090	)
Cash paid	$	7,197

McMoRan oil and gas properties interests acquisition

On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin field (“Bayou Carlin Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $80 million. This acquisition is effective January 1, 2013. We are the operator of these properties.

Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income. The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	63,186
Oil and natural gas properties – unevaluated		17,184
Net working capital		12
Asset retirement obligations		(382	)
Cash paid	$	80,000

Roda oil and gas properties interests acquisition

On March 14, 2013, we acquired 100% of the interests (“Roda Interests”) held by Roda Drilling LP (“Roda”) in the Bayou Carlin field for $34 million. This acquisition is effective January 1, 2013.

Revenues and expenses related to the Roda Interests from the closing date of March 14, 2013 are included in our consolidated statements of income. The acquisition of the Roda Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	33,615
Net working capital		500
Asset retirement obligations		(115	)
Cash paid	$	34,000

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

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ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 3 — Acquisitions  – (continued)

Apache Joint Venture

On February 1, 2013, we entered into an Exploration Agreement (“Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central Gulf of Mexico Shelf. We have a 25% participation interest in the Agreement, which expires on February 1, 2018.

The area of mutual interest (“AMI”) under this agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million. We have presently consented to participate in drilling one well and have an option to participate in two other wells under the current drilling program.

As of March 31, 2013, we paid consideration of approximately $2.5 million, being our participation interest, to Apache for non-producing primary-term leases.

Note 4 — Property and Equipment

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

	March 31, 2013		June 30, 2012
Oil and gas properties
Proved properties	$	4,982,071	$	4,375,984
Less: Accumulated depreciation, depletion, amortization and impairment		2,373,186		2,096,531
Proved properties		2,608,885		2,279,453
Unproved properties		539,354		418,760
Oil and gas properties		3,148,239		2,698,213
Other property and equipment		31,273		22,132
Less: Accumulated depreciation		15,159		12,599
Other property and equipment		16,114		9,533
Total property and equipment – net of accumulated depreciation, depletion, amortization and impairment	$	3,164,353	$	2,707,746

Note 5 — Equity Method Investments

  20% interest in Energy XXI M21K, LLC (“EXXI M21K”)

We own a 20% interest in EXXI M21K. EXXI M21K engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).

On June 4, 2012, M21K entered into a Purchase and Sale Agreement (“PSA Agreement”) with EP Energy E&P Company, L.P. (“EP Energy”) to acquire interests in certain oil and gas fields owned by EP Energy. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition is January 1, 2012.

On July 19, 2012, M21K closed on the acquisition and we paid our share of the remaining purchase price of $16 million to EP Energy, prior to final adjustments. EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K (“M21K First Lien Credit Agreement”). Simultaneous with the closing of the acquisition of assets from EP Energy, M21K entered into the First Amendment to the M21K First Lien Credit Agreement, which made technical changes to defined terms and hedging requirements, as well as establishing the borrowing base under the facility at $25 million.

12

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 5 — Equity Method Investments  – (continued)

On December 12, 2012, in conjunction with the name change from Natural Gas Partners Assets, LLC to M21K, LLC, M21K entered into the Second Amendment to the M21K First Lien Credit Agreement to reflect the name change and make technical changes to borrowing procedures.

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement that made technical modification of a defined term and reduced the borrowing base to $24 million with further reduction to $20 million within ninety days from the amendment date.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K. See Note 14 — Related Party Transactions of Notes to Consolidated Financial Statements in this Quarterly Report.

As of March 31, 2013, our investment in EXXI M21K was approximately $12.7 million, and we had incurred $1.7 million and $2.0 million in equity losses for the three months and nine months ended March 31, 2013, respectively.

  49% interest in Ping Energy XXI Limited (“Ping Energy”)

Our wholly-owned subsidiary Energy XXI International Limited (“EXXI International”) owns a 49% interest in Ping Energy, which is active in the pursuit to identify and acquire exploratory, developmental and producing oil and gas properties in South East Asia.

As of March 31, 2013, our investment in Ping Energy was approximately $0.7 million and we had incurred $0.9 million and $2.7 million in equity losses for the three months and nine months ended March 31, 2013, respectively.

Note 6 — Long-Term Debt

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

	March 31, 2013		June 30, 2012
Revolving credit facility	$	212,831	$	—
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
4.14% Promissory Note due 2017		5,289		—
Derivative instruments premium financing		31,387		17,387
Capital lease obligation		1,065		957
Total debt		1,250,572		1,018,344
Less current maturities		23,428		4,284
Total long-term debt	$	1,227,144	$	1,014,060

Maturities of long-term debt as of March 31, 2013 are as follows (in thousands):

Twelve Months Ended March 31,
2014	$	23,428
2015		222,331
2016		813
2017		465
2018		753,535
Thereafter		250,000
Total	$	1,250,572

13

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Long-Term Debt  – (continued)

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by our indirect, wholly-owned subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), in May 2011. This facility, amended most recently on May 1, 2013, has lender commitments of $1,700 million and matures on April 9, 2018. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions.

On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement, which provided EGC the ability to make distributions to us for various purposes, subject to varying limitations depending on the purpose of the distribution. The ability of EGC to make dividends was subject to EGC meeting minimum liquidity and maximum revolver utilization thresholds, and were further limited to an aggregate cumulative amount equal to $70 million plus 50% of our cumulative Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter. The ability of EGC to make dividend payments to us was modified in subsequent amendments.

On May 24, 2012, EGC entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit Agreement which provided further increased flexibility to make payments from EGC to us and/or our other subsidiaries. The Second Amendment includes the following: (a) removal of limitations on the ability of EGC to finance hedge option premiums; (b) technical modifications in regard to the ability of EGC to reposition hedges; (c) adjustment of definitions and other provisions to further increase the ability of EGC to make distributions to us and/or our subsidiaries; and (d) technical corrections in connection with the replacement of one of the lenders (including that lender’s role as an issuer of a letter of credit) under the First Lien Credit Agreement.

On October 19, 2012, EGC entered into the Third Amendment (the “Third Amendment”) to the First Lien Credit Agreement. The Third Amendment provides changes, supplements, and other modifications for information specific to the lenders under the First Lien Credit Agreement and increases the borrowing base to $825 million.

On April 9, 2013, EGC entered into the Fourth Amendment (the “Fourth Amendment”) to the First Lien Credit Agreement. The Fourth Amendment includes the following: (a) extension of the maturity date to April 9, 2018 (b) increase of commitments under the First Lien Credit Agreement from $925 million to $1,700 million, (c) increase in the borrowing base to $850 million, (d) reduction of the ranges of applicable margins on all borrowing by 0.25% to 0.50%, (e) approval of an increase in the cash distribution basket under which EGC can make dividend payments on its preferred and common stock, from $17 million to $50 million per calendar year, (f) increase in the general basket of permitted unsecured indebtedness from $250 million to $750 million, subject to a reduction in the borrowing base of 25 percent of any unsecured indebtedness issued in excess of $250 million, and (g) approval of additional ability of an affiliated entity to reinsure the assets and operations of EGC and its subsidiaries.

On May 1, 2013, EGC entered into the Fifth Amendment (the “Fifth Amendment”) to the First Lien Credit Agreement. The Fifth Amendment provides changes and other modifications to the First Lien Credit Agreement to increase the ability of EGC to make dividends and other distributions to us. Under the Amendment, EGC now can make such dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, EGC and its subsidiaries have liquidity, in the

14

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Long-Term Debt  – (continued)

form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement. Further, the amendment limits the total aggregate distributions made by EGC to a maximum of $70 million plus 50% of the cumulative consolidated net income of EGC between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to EGC.

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

As of March 31, 2013, we were in compliance with all covenants under our First Lien Credit Agreement.

High Yield Facilities

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million aggregate principal amount of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Senior Notes”). On July 8, 2011, we exchanged $749 million aggregate principal amount of the 9.25% Notes for $749 million aggregate principal amount of newly issued notes registered under the Securities Act of 1933, as amended (the “Securities Act”) which bear identical terms and conditions as the 9.25% Senior Notes. The trading restrictions on the remaining $1 million principal amount of the 9.25% Senior Notes were lifted on December 17, 2011.

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which is defined in the indenture governing the 9.25% Senior Notes.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2013 was $848.9 million based on quoted prices. There is no active market for the 9.25% Senior Notes; therefore, the fair value is classified within Level 2.

The 9.25% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

7.75% Senior Notes

On February 25, 2011, EGC issued $250 million aggregate principal amount of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Senior Notes”). On July 7, 2011, we exchanged the full $250 million aggregate principal amount of the 7.75% Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act which bear identical terms and conditions as the 7.75% Senior Notes.

15

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Long-Term Debt  – (continued)

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which is defined in the indenture governing the 7.75% Senior Notes.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2013 was $271.3 million based on quoted prices. There is no active market for the 7.75% Senior Notes; therefore, the fair value is classified within Level 2.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

Promissory Note

In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note we are required to make a monthly payment of approximately $52,000 and one lump-sum payment of $3.3 million at maturity, in October 2017. This note carries an interest of 4.14% per annum.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of March 31, 2013 and June 30, 2012, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $31.4 million and $17.4 million, respectively.

Interest Expense

For the three months and nine months ended March 31, 2013 and 2012, interest expense consisted of the following (in thousands):

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Revolving credit facility	$	3,330	$	2,201	$	8,185	$	7,291
9.25% Senior Notes due 2017		17,343		17,344		52,031		52,031
7.75% Senior Notes due 2019		4,843		4,843		14,531		14,531
Amortization of debt issue cost – Revolving credit facility		1,261		1,238		3,762		3,645
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552		552		1,655		1,655
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97		97		291		291
Derivative instruments financing and other		256		612		884		2,994
	$	27,682	$	26,887	$	81,339	$	82,438

16

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 7 — Notes Payable

In May 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $26.0 million and bore interest at an annual rate of 1.556%. The note matured and was repaid on December 26, 2012.

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $3.6 million and bears interest at an annual rate of 1.667%. The note amortizes over the remaining term of the insurance, which matures May 1, 2013. The balance outstanding as of March 31, 2013 was $0.7 million.

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums. The note was for a total face amount of $0.6 million and bears interest at an annual rate of 1.774%. The note amortizes over the remaining term of the insurance, which matures October 23, 2013. The balance outstanding as of March 31, 2013 was $0.3 million.

Note 8 — Asset Retirement Obligations

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

Balance at June 30, 2012	$	301,415
Liabilities acquired		6,940
Liabilities incurred		11,605
Liabilities settled		(29,570	)
Accretion expense		23,057
Total balance at March 31, 2013		313,447
Less current portion		30,130
Long-term balance at March 31, 2013	$	283,317

Note 9 — Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions, for our derivative transactions to reduce the concentration of exposure to any individual counterparty and 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. We designate a majority of our derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

When we discontinue cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

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

17

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

consisting of 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, ICE) plus the difference between the purchased put and the sold put strike price.

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the quarter ended September 30, 2011, we began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and price risk.

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 helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended March 31, 2013, and received $181.1 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of March 31, 2013, we had $13.5 million of monetized amounts remaining in OCI of which $4.5 million will be recognized during each of the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

During the quarter ended March 31, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and will be recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of March 31, 2013, we had $2.0 million in deferred hedge revenue of which $0.6 million, $0.7 million, and $0.7 million will be recognized during the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

18

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

As of March 31, 2013, we had the following net open crude oil derivative positions:

								Weighted Average Contract Price
								Swaps		Collars/Put Spread
Period	Type of Contract		Index		Volumes (MBbls)			Fixed Price		Sub Floor		Floor		Ceiling
April 2013 – December 2013		Three-Way Collars		Oil-Brent-IPE		2,570	(1)			$	85.72	$	105.72	$	126.72
April 2013 – December 2013		Put Spreads		Oil-Brent-IPE		1,830					87.00		106.25
April 2013 – December 2013		Three-Way Collars		NYMEX-WTI		1,375					70.00		90.00		136.32
April 2013 – December 2013		Collars		NYMEX-WTI		963							73.57		105.63
April 2013 – December 2013		Swaps		NYMEX-WTI		138		$	86.60
April 2013 – December 2013		Swaps		NYMEX-WTI		(138	)		88.20
January 2014 – December 2014		Three-Way Collars		Oil-Brent-IPE		2,373					68.08		88.08		130.88
January 2014 – December 2014		Collars		Oil-Brent-IPE		730							90.00		108.38
January 2014 – December 2014		Three-Way Collars		NYMEX-WTI		3,650					70.00		90.00		137.14
January 2015 – December 2015		Three-Way Collars		Oil-Brent-IPE		1,825					72.00		92.00		111.56

(1) The Oil-Brent-IPE three-way collars for the period from April 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

As of March 31, 2013, we had the following open natural gas derivative positions:

							Weighted Average Contract Price
							Collars/Call Spread
Period	Type of Contract		Index		Volumes (MMBtu)		Sub Floor		Floor		Ceiling
April 2013 – December 2013		Three-Way Collars		NYMEX-HH		8,250	$	4.07	$	4.93	$	5.87
January 2014 – December 2014		Call Spread		NYMEX-HH		913		4.20		5.00

19

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):

	Asset Derivative Instruments								Liability Derivative Instruments
	March 31, 2013				June 30, 2012				March 31, 2013				June 30, 2012
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments		Current	$	37,233		Current	$	66,716		Current	$	13,622		Current	$	34,462
		Non-Current		43,294		Non-Current		103,462		Non-Current		26,896		Non-Current		58,229
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		4,621		Current		326		Current		4,444		Current		83
		Non-Current		319		Non-Current		451		Non-Current		144		Non-Current		188
Total			$	85,467			$	170,955			$	45,106			$	92,962

The effect of derivative instruments on our consolidated statements of income was as follows (in thousands):

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(1,084	)	$	3,009		$	(10,455	)	$	2,576
Natural gas sales		(2,340	)		(4,128	)		(12,879	)		(23,528	)
Total cash settlements		(3,424	)		(1,119	)		(23,334	)		(20,952	)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments		(816	)		3,388			3,800			1,713
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		(41	)		23			1,832			(5,001	)
Unrealized mark to market (gain) loss		225			84			123			782
Total (gain) loss on derivative financial instruments		(632	)		3,495			5,755			(2,506	)
Total gain	$	(4,056	)	$	2,376		$	(17,579	)	$	(23,458	)

20

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Derivative Financial Instruments  – (continued)

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

Location of (Gain)/Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Three Months Ended March 31, 2013
Commodity Derivative Instruments	$	5,964
Revenues				$	(4,657	)
(Gain) loss on derivative financial instruments							$	(816	)
Total	$	5,964		$	(4,657	)	$	(816	)
Three Months Ended March 31, 2012
Commodity Derivative Instruments	$	39,757
Revenues				$	(1,349	)
(Gain) loss on derivative financial instruments							$	3,388
Total	$	39,757		$	(1,349	)	$	3,388
Nine Months Ended March 31, 2013
Commodity Derivative Instruments	$	43,482
Revenues				$	(18,526	)
(Gain) loss on derivative financial instruments							$	3,800
Total	$	43,482		$	(18,526	)	$	3,800
Nine Months Ended March 31, 2012
Commodity Derivative Instruments	$	(52,837	)
Revenues				$	(16,658	)
(Gain) loss on derivative financial instruments							$	1,713
Total	$	(52,837	)	$	(16,658	)	$	1,713

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $15.9 million ($10.3 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position from counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At March 31, 2013, we had no deposits for collateral with our counterparties.

21

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 10 — Income Taxes

We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods. Currently, our estimated annual effective tax rate is approximately 39.5%. The variance from the U.S. statutory rate of 35% is primarily due to the presence of common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit. Our Bermuda companies continue to report a tax provision reflecting accrued 30% U.S. withholding tax required on any interest (and interest equivalent) payments made from the U.S. companies to the Bermuda companies. We have accrued an additional withholding obligation of $10.4 million for the nine months ended March 31, 2013.

In this quarter, we adjusted our valuation allowance to reflect the annual reconciliation of our U.S. income tax return just filed to our previous estimates. We have a remaining valuation allowance of $30.0 million (related to certain State of Louisiana tax attributes and other property matters). In this quarter, we made a cash withholding tax payment of $3.9 million on outbound accrued intercompany interest paid to Bermuda. This withholding tax was previously accrued and did not result in additional income tax expense being recognized. Similar cash withholding tax payments would be made in the future when additional intercompany interest is paid. While we have not made a cash income tax payment in this quarter, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (AMT) in subsequent quarters may be required (possibly as early as the fourth quarter of fiscal year 2013). At this time, we do not believe the federal estimated income tax payments for this fiscal year will exceed $5 million. We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

Note 11 — Stockholders’ Equity

Common Stock

On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on The NASDAQ Global Select Market (“NASDAQ”). Our common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders.

We paid quarterly cash dividends of $0.07 per share to holders of the Company’s common stock for the quarters ended June 30, 2012, September 30, 2012 and December 31, 2012 on September 14, 2012, December 14, 2012 and March 15, 2013 respectively.

On May 1, 2013, our board of directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on June 14, 2013 to shareholders of record on May 31, 2013.

Preferred Stock

Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.

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

22

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 11 — Stockholders’ Equity  – (continued)

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

Conversion of Preferred Stock

During the nine months ended March 31, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.

Note 12 — Supplemental Cash Flow Information

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

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Cash paid for interest	$	3,402	$	4,698	$	50,591	$	56,721
Cash paid for income taxes		4,056		—		7,017		—

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

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012
Financing of insurance premiums	$	(1,266	)	$	(8,558	)	$	(21,131	)	$	(19,215	)
Derivative instruments premium financing		12,780			15,557			14,001			12,869
Preferred stock dividends		(53	)		(138	)		(593	)		(138	)
Additions to property and equipment by recognizing asset retirement obligations		1,816			700			11,605			2,037

Note 13 — 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 (“Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Restricted 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 Restricted Stock Units.

Performance Units

For fiscal 2010, 2011 and 2012, we also awarded performance units (“Performance Units”). Of the total Performance Units awarded, 25% are time-based Performance Units (“Time-Based Performance Units”) and 75% are total shareholder return performance-based units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.

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

23

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 13 — Employee Benefit Plans  – (continued)

Historically, we have paid all Restricted Stock Units vesting awards in cash. Performance Unit awards were paid 50% in common stock and future vesting of the Performance Units may be paid in common stock at the discretion of our board of directors.

We recognized compensation expense related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Restricted Stock Units	$	1,941	$	6,897	$	9,668	$	17,032
Performance Units		231		10,055		13,086		27,007
Total compensation expense recognized	$	2,172	$	16,952	$	22,754	$	44,039

As of March 31, 2013, we have 886,626 unvested Restricted Stock Units and 5,170,042 unvested Performance Units.

Stock Purchase Plan

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or that have been newly issued by us. During the nine months ended March 31, 2013 and 2012, we issued 208,988 shares and 277,980 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from January 1, 2013 to June 30, 2013. We use Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. The compensation expense recognized and shares issued under Employee Stock Purchase Plan were as follows (in thousands, except for shares):

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Compensation expense	$	221	$	215	$	598	$	516
Shares issued		—		—		27,608		21,015

Stock Options

In September 2008, our board of directors granted 300,000 stock options to certain officers. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. As of March 31, 2013, 100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.

24

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 13 — Employee Benefit Plans  – (continued)

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

	Nine Months Ended March 31,
	2013			2012
	Shares Under Option		Weighted Ave. Exercise Price	Shares Under Option			Weighted Ave. Exercise Price
Beginning balance		—			100,000		$	17.50
Vested		—			(100,000	)		17.50
Ending balance		—			—

Our net income for the three and nine months ended March 31, 2013 and 2012 includes approximately $0, $0, $0 and $58,000, respectively of compensation costs related to stock options.

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

Defined Contribution Plans

Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401(k) Plan that provides for matching. The contributions under these plans were as follows (in thousands):

	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013		2012
Profit Sharing Plan	$	(481	)	$	(49	)	$	1,712	$	1,756
401(k) Plan		1,587			1,360			2,948		2,866
Total contributions	$	1,106		$	1,311		$	4,660	$	4,622

Note 14 — Related Party Transactions

We have a 20% interest in EXXI M21K and a 49% interest in Ping Energy. We account for these investments using the equity method. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

We are a guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K estimated at $65 million and $1.8 million, respectively. For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years. As of March 31, 2013, we have received $1.2 million related to such guarantee.

25

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 15 — 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 convertible preferred stock, restricted stock and other common stock equivalents. The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Net income	$	40,436	$	91,252	$	100,028	$	254,672
Preferred stock dividends		2,873		2,739		8,623		10,151
Induced Conversion of Preferred Stock		—		6,058		—		6,058
Net income available for common stockholders	$	37,563	$	82,455	$	91,405	$	238,463
Weighted average shares outstanding for basic EPS		79,365		77,454		79,280		76,803
Add dilutive securities		8,151		9,899		8,191		10,382
Weighted average shares outstanding for diluted EPS		87,516		87,353		87,471		87,185
Earnings per share
Basic	$	0.47	$	1.06	$	1.15	$	3.10
Diluted	$	0.46	$	1.04	$	1.14	$	2.92

Note 16 — 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 effect on our consolidated financial position, results of operations or cash flows.

Lease Commitments.  We have a non-cancelable operating lease for office space and other that expires on March 31, 2018. Future minimum lease commitments as of March 31, 2013 under the operating lease are as follows (in thousands):

Twelve Months Ended March 31,
2014	$	2,821
2015		2,980
2016		2,776
2017		2,849
2018		2,559
Thereafter		1,936
Total	$	15,921

Rent expense, including rent incurred on short-term leases, for the three months ended March 31, 2013 and 2012 was $861,000 and $942,000, respectively, and for the nine months ended March 31, 2013 and 2012 was $2,122,000 and $1,839,000, respectively.

Letters of Credit and Performance Bonds.  We had $225.3 million in letters of credit and $44.4 million of performance bonds outstanding as of March 31, 2013.

Line of Credit.  Our equity method investee, EXXI M21K, of which we own 20%, is a guarantor of a $100 million line of credit entered into by M21K on February 23, 2012. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

26

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 16 — Commitments and Contingencies  – (continued)

Guarantee.   We are a guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report. We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K estimated at $65 million and $1.8 million, respectively. For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years. See Note 14 — Related Party Transactions of Notes to Consolidated Financial Statements in this Quarterly Report.

Drilling Rig Commitments.  As of March 31, 2013, we have entered into seven drilling rig commitments:

1) January 16, 2013 to June 30, 2013 at $49,000 per day

2) January 1, 2013 to September 30, 2013 at $110,000 per day

3) January 1, 2013 to September 30, 2013 at $110,000 per day

4) March 5, 2013 to September 5, 2013 at $130,000 per day

5) October 2, 2012 to June 1, 2013 at $90,000 per day

6) February 15, 2013 to July 15, 2013 at $39,000 per day

7) March 15, 2013 to July 1, 2013 at $36,000 per day

At March 31, 2013, future minimum commitments under these contracts totaled $70.2 million.

Note 17 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal

27

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 17 — Fair Value of Financial Instruments  – (continued)

(or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

• Level 1 — quoted prices in active markets for identical assets or liabilities.

• Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

• Level 3 — unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 1				Level 2
	March 31, 2013		June 30, 2012		March 31, 2013		June 30, 2012
Assets:
Oil and natural gas derivatives					$	85,467	$	170,955
Liabilities:
Oil and natural gas derivatives					$	45,106	$	92,962
Restricted stock units	$	6,964	$	15,124
Time-based performance units		2,397		4,434
Total liabilities	$	9,361	$	19,558	$	45,106	$	92,962

The following table describes the changes to our Level 3 financial instruments (in thousands):

	Level 3
	Nine Months Ended March 31,
	2013			2012
Liabilities:
Performance-based performance units
Balance at beginning of period	$	22,855		$	20,305
Vested		(23,161	)		(23,807	)
Grants and changes in fair value charged to general and administrative expense		10,264			23,320
Balance at end of period	$	9,958		$	19,818

28

ENERGY XXI (BERMUDA) LIMITED
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 18 — Prepayments and Accrued Liabilities

Prepayments and accrued liabilities consist of the following (in thousands):

	March 31, 2013		June 30, 2012
Prepaid expenses and other current assets
Advances to joint interest partners	$	3,059	$	12,966
Insurance		6,801		30,515
Inventory		4,127		4,849
Royalty deposit		1,961		2,443
Short-term stock investment		23		8,786
Other		6,823		3,470
Total prepaid expenses and other current assets	$	22,794	$	63,029
Accrued liabilities
Advances from joint interest partners	$	10,264	$	301
Employee benefits and payroll		29,132		53,541
Interest		28,037		3,721
Accrued hedge payable		4,228		136
Undistributed oil and gas proceeds		46,757		54,484
Other		3,146		6,635
Total accrued liabilities	$	121,564	$	118,818

Note 19 — Subsequent Events

EGC entered into the Fourth and Fifth Amendments to the First Lien Credit Agreement on April 9, 2013 and May 1, 2013, respectively. See Note 6 — Long-Term Debt of Notes to Consolidated Financial Statements in this Quarterly Report.

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement. See Note 5 — Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

On May 1, 2013, our board of directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on June 14, 2013 to shareholders of record on May 31, 2013.

On May 1, 2013, our Board of Directors approved a stock repurchase program authorizing Energy XXI, Inc., a Delaware subsidiary of the Company (“Energy XXI, Inc.”), to repurchase up to $250 million in value of the Company’s common stock for an extended period of time, in one or more open market transactions. The Company also announced that in connection with the repurchase program, the Board of Directors has also approved a 10b5-1 plan, allowing Energy XXI, Inc. to repurchase the Company’s shares at times when it otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. Energy XXI, Inc. intends to fund the share repurchases through borrowings under EGC’s revolving credit facility and repurchased shares will be retained by Energy XXI, Inc., subject to transfer to the Company where they may be retired. Such authorized repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity.

29

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

Overview

We are an independent oil and natural gas exploration and production company with properties focused in the U.S. Gulf Coast and the Gulf of Mexico. Our business strategy includes: (1) acquiring producing oil and gas properties; (2) exploiting and exploring our core assets to enhance production and ultimate recovery of reserves; and (3) utilizing a portion of our capital program to explore the ultra-deep trend for potential oil and gas reserves. We are one of the largest oil producers on the Gulf of Mexico shelf with interest in six of the eleven largest oil fields on the Gulf of Mexico shelf.

Our operations are geographically focused, and we target acquisitions of oil and gas properties to 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. For the year ended June 30, 2012, excluding acquisitions, approximately 33% of our capital expenditures were associated with the exploitation of existing properties.

At June 30, 2012, our total proved reserves were 119.6 MMBOE of which 71% were oil and 68% were classified as proved developed and we operated or had an interest in 450 gross producing wells on 239,502 net developed acres, including interests in 41 producing fields. All of our properties are primarily located on the U.S. Gulf Coast and in the Gulf of Mexico, with approximately 91% of our proved reserves being offshore. This concentration facilitates our ability to manage the operated fields efficiently, and our high number of wellbore locations provides diversification of our production and reserves. We believe operating our assets is key to our strategy, and approximately 85% of our proved reserves are on properties operated by us. We have a seismic database covering approximately 5,670 square miles, primarily focused on our existing operations. This database has helped us identify approximately 194 drilling opportunities. We believe the mature legacy fields on our acquired properties will lend themselves well to our aggressive exploitation strategy, and we expect to identify incremental exploration opportunities on the properties.

We are actively engaged in a program designed to manage our commodity price risk, and we seek to hedge the majority of our proved developed producing reserves to enhance cash flow certainty and predictability. In connection with our acquisitions, we typically enter into hedging arrangements to minimize commodity downside exposure. We believe our disciplined risk management strategy provides substantial price protection, as our cash flow on the hedged portion is driven by production results rather than commodity prices. We believe this greater price certainty allows us to more efficiently manage our cash flows and allocate our capital resources.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Multiple events during 2009 through 2012 involving numerous countries and financial institutions and the market, in general, impacted liquidity within the capital markets throughout the United States and around the world. Despite efforts by the U.S. Treasury Department and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector, capital markets remain constrained. As a result, we expect that our ability to raise debt and equity and the terms on which we can raise capital will be dependent upon the condition of the capital markets.

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

Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. As required by our revolving credit facility, we have mitigated this

30

volatility through December 2015 by implementing a hedging program on a portion of our total anticipated production during this time frame. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

We are also subject to natural gas and oil production declines. We attempt to replace this declining production through our drilling and recompletion program and acquisitions. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues. Consistent with our business strategy, we intend to invest the capital necessary to maintain our production at existing levels over the long-term provided that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue additional debt and equity on acceptable terms, or at all, and we may be unable to refinance our revolving credit facility when it expires. Additionally, should commodity prices decline, our borrowing base under our revolving credit facility may be reduced thereby eliminating the working capital necessary to fund our capital spending program as well as potentially requiring us to repay certain of our outstanding indebtedness. The explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico, as well as the resulting oil spill, have also led to increased governmental regulation of our and our industry’s operations in a number of areas, including health and safety, environmental, and licensing, any of which could result in increased costs or delays in our current and future drilling operations.

Operational Highlights

Ultra-Deep Shelf Exploration and Development Activity

We participate with McMoRan Exploration Company in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico. Data received to date from ultra-deep shelf drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, we have also identified approximately 15 ultra-deep prospects in shallow water near existing infrastructure. In addition, we will participate in three onshore ultra-deep prospects located in South Louisiana. The ultra-deep drilling plans in calendar years 2008 through 2013 included the Blackbeard East, Lafitte, Blackbeard West, Lomond North, Blackbeard West No. 2 and Lineham Creek exploratory wells and delineation drilling at Davy Jones. Near term sub-salt drilling plans include 2 to 3 exploratory wells. We expect to have more than sufficient liquidity to fund our current commitments related to our ultra-deep trend exploration and development activity.

As previously reported, we have drilled two successful sub-salt wells in the Davy Jones field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones offset appraisal well (Davy Jones No. 2), which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. The Davy Jones field involves a large ultra-deep structure encompassing four Outer Continental shelf lease blocks (20,000 acres). As of March 31, 2013, our investment in both wells in the Davy Jones field totaled approximately $148 million.

Davy Jones.  The Davy Jones No. 1 well on South Marsh Island Block 230 was successfully completed in March 2012. The perforation of the Wilcox “D” sand in March 2012 resulted in positive pressure build-up in the wellbore followed by a gas flare from the well. Initial samples indicated that the natural gas from the Wilcox “D” sand is high quality and contains low levels of CO2 and no H2S is present. Blockage from drilling fluid associated with initial drilling operations prevented the group from obtaining a measurable flow rate. During early January, the operator reperforated the Wilcox zones in the well with through-tubing perforating guns. Recent operations confirm that the perforations are open and that fluid could be injected through the perforations into the formation. The operator has moved the rig off location while a large-scale hydraulic fracture treatment is designed and results at Lineham Creek studied to decide further operation.

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Blackbeard East.  The Blackbeard East ultra-deep exploration by-pass well was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. The Frio sands are the first hydrocarbon bearing Frio sands encountered either on the Gulf of Mexico shelf or in the deepwater offshore Louisiana. Pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. The operator held the lease rights to South Timbalier Block 144 through August 17, 2012 and during the quarter submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement (“BSEE”). The operator plans to test and complete the upper Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. The group’s ability to preserve the interest in Blackbeard East will require approval from the BSEE of the development plans. Blackbeard East is located in 80 feet of water on South Timbalier Block 144. As of March 31, 2013, our investment in the well totaled approximately $51 million.

Lafitte.  The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Vicksburg, and Sparta carbonate. The Upper Eocene sands are the first hydrocarbon bearing Upper Eocene sands encountered either on the Gulf of Mexico shelf or in the deepwater offshore Louisiana. The group is evaluating development options associated with these formations. In October 2012, the operator submitted initial development plans to complete and test the Jackson/Yegua sands in the Upper Eocene with the BSEE. As of March 31, 2013, our investment in the well totaled approximately $40 million.

Blackbeard West.  Information gained from the Blackbeard East and Lafitte wells will enable us to consider priorities for future operations at Blackbeard West. As previously reported, the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation, and the well was temporarily abandoned. The Blackbeard West No. 2 ultra-deep exploration well commenced drilling on November 25, 2011 and reached total depth of 25,584 feet in January 2013. Initial completion efforts are expected to focus on the development of laminated sands in the Middle Miocene located at approximately 24,000 feet. Through logs and core data, the operator has identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,800 and 24,000 feet. Initial completion efforts are expected to focus on the development of approximately 50 net feet of laminated sands in the Middle Miocene located at approximately 24,000 feet. Additional development opportunities in the well bore include approximately 80 net feet of potential low-resistivity pay at approximately 22,400 feet and an approximate 75 foot gross section at approximately 20,900 feet. Pressure and temperature data indicate that a completion at these depths could utilize conventional equipment and technologies. Our investment in both Blackbeard West wells totaled approximately $57 million at March 31, 2013.

Lineham Creek.  The Lineham Creek exploration prospect, operated by Chevron U.S.A. Inc., which is located onshore in Cameron Parish, Louisiana commenced drilling on March 31, 2011. The well, which is targeting Eocene and Paleocene objectives below the salt weld, is currently drilling below 29,400 feet towards a proposed total depth of 30,500 feet. The well encountered positive results above 24,000 feet in November 2012. Detailed whole core and log data obtained will be used in evaluating future plans for all ultra-deep wells. As of March 31, 2013, our investment in the Lineham Creek well totaled approximately $16 million.

Lomond North.  The Lomond North exploration prospect in the Highlander area where multiple high potential prospects on an 80,000 acre position have been identified is operated by McMoRan Exploration Company. The well, which is located onshore in St. Martin Parish, Louisiana, commenced drilling on September 19, 2012. The well, which is targeting Eocene, Creataceous and Paleocene objectives below the salt weld, is currently drilling below 18,250 feet towards a proposed total depth of 30,000 feet. As of March 31, 2013, our investment in the Lomond North well totaled approximately $15 million.

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Known Trends and Uncertainties

Continued Volatility in Commodity Price Environment.  Commodity prices are one of our key drivers of earnings generation and net operating cash flow and are affected by many factors that are outside of our control. Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. We actively seek to mitigate this volatility through the implementation of a hedging program that covers a portion of our total anticipated production through December 2015. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report for a detailed discussion of our hedging program.

Ongoing Disruptions in Global Financial Markets.  Multiple events during 2009 through 2012 involving numerous countries and financial institutions impacted liquidity within the capital markets throughout the United States and around the world. Despite efforts by the U.S. Treasury Department and banking regulators in the United States, Europe and other nations around the world to provide liquidity and stability to the financial sector, access to capital markets has remained somewhat constrained. While we currently expect to fund our capital program from existing cash flow from operations, we may be required to issue equity or debt to maintain adequate liquidity to implement our capital program. To extent that access to capital markets remains constrained, we expect that our ability to raise debt and equity capital, and the terms on which we can raise such capital, may be somewhat restricted.

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

The Company has contracted with an emergency and spill response management consultant, to provide management expertise, personnel and equipment, under the supervision of the Company, in the event of an incident requiring a coordinated response. Additionally, the Company is a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the GOM and has capabilities to simultaneously respond to multiple spills. CGA has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), a private, not-for-profit marine spill response organization which is funded by the Marine Preservation Association, a member-supported, not-for-profit organization created to assist the petroleum and energy-related industries by addressing problems caused by oil spills on water. In the event of a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.

Hurricanes.  Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes is becoming more difficult to obtain. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs. During the nine months ended March 31, 2013 we were impacted by Hurricane Isaac which resulted in weather related downtime on properties where we have an interest. Additionally, there was no material damage to any assets or company property.

Ultra-Deep Trend Exploration and Development.  We have participated in eight ultra-deep wells to date. Of these wells, one has been temporarily abandoned pending further evaluation, four are temporarily abandoned pending facilities and completions, two are currently drilling and one is currently being tested. These projects have similar geological characteristics as deepwater prospects with a potential for significant reserves. The shallow water ultra-deep trend wells are some of the deepest wells ever drilled in the world and are subject to very high pressures and temperatures. The drilling, logging and completion techniques are near the limits of existing technologies. As a result, new technologies and techniques are being developed to deal

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with these challenges. The use of advanced drilling technologies involves a higher risk of technological failure and potentially higher costs. In addition, there can be delays in completion due to necessary equipment that is specially ordered to handle the challenges of ultra-deep wells. The shallow water ultra-deep is considered in the industry as Ultra High Pressure High Temperature (“U-HPHT”). Generally this refers to pressures above 15,000 psig and temperatures above 300°F. The U-HPHT in the play range from 400°F to 474°F and bottom hole pressures from 26,500 psig to over 30,000 psig. Completion equipment has been designed to handle surface pressures to 25,000 psig and have been tested to 37,500 psig. There were 18 new technologies developed for this project which went through extensive design reviews, computational analysis and finally physical testing to meet requirements for use in U-HPHT wells. All equipment is currently qualified to 25,000 psig and 450°F. Work is ongoing for qualifying some of the same equipment for 30,000 psig surface. We target to spend less than 10% of our budgeted cash flow on our exploration activities on the ultra-deep. Based on the results of these wells, our proved reserves may vary from our current 71% oil composition.

Operational Information (In thousands except for unit amounts)

	Quarter Ended
	Mar. 31, 2013			Dec. 31, 2012			Sept. 30, 2012			June 30, 2012			Mar. 31, 2012
Operating Highlights
Operating revenues
Crude oil sales	$	273,280		$	280,953		$	242,830		$	314,639		$	315,723
Natural gas sales		27,070			29,657			17,396			19,657			19,154
Hedge gain		3,424			9,909			10,001			7,650			1,119
Total revenues		303,774			320,519			270,227			341,946			335,996
Percent of operating revenues from crude oil
Prior to hedge gain		91	%		90	%		93	%		94	%		94	%
Including hedge gain		90	%		89	%		92	%		92	%		93	%
Operating expenses
Lease operating expense
Insurance expense		7,473			8,810			8,992			6,825			7,138
Workover and maintenance		19,166			20,217			10,113			21,070			15,885
Direct lease operating expense		59,666			56,895			63,376			59,306			55,424
Total lease operating expense		86,305			85,922			82,481			87,201			78,447
Production taxes		1,352			1,166			1,247			2,414			1,499
Gathering and transportation		4,411			6,098			7,991			4,358			2,465
DD&A		88,727			105,856			84,795			106,644			88,448
General and administrative		16,092			19,319			23,888			19,733			25,075
Other – net		7,017			8,621			13,174			5,186			13,257
Total operating expenses		203,904			226,982			213,576			225,536			209,191
Operating income	$	99,870		$	93,537		$	56,651		$	116,410		$	126,805
Sales volumes per day
Natural gas (MMcf)		89.4			90.9			67.1			92.5			83.7
Crude oil (MBbls)		28.6			29.4			26.1			32.2			31.4
Total (MBOE)		43.5			44.6			37.3			47.6			45.3
Percent of sales volumes from crude oil		66	%		66	%		70	%		68	%		69%

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	Quarter Ended
	Mar. 31, 2013		Dec. 31, 2012		Sept. 30, 2012		June 30, 2012		Mar. 31, 2012
Average sales price
Natural gas per Mcf	$	3.37	$	3.55	$	2.82	$	2.34	$	2.52
Hedge gain per Mcf		0.29		0.60		0.89		0.55		0.54
Total natural gas per Mcf	$	3.66	$	4.15	$	3.71	$	2.89	$	3.06
Crude oil per Bbl	$	106.11	$	103.79	$	101.03	$	107.34	$	110.54
Hedge gain (loss) per Bbl		0.42		1.80		1.87		1.03		(1.05	)
Total crude oil per Bbl	$	106.53	$	105.59	$	102.90	$	108.37	$	109.49
Total hedge gain per BOE	$	0.87	$	2.42	$	2.91	$	1.77	$	0.27
Operating revenues per BOE	$	77.58	$	78.15	$	78.72	$	78.90	$	81.43
Operating expenses per BOE
Lease operating expense
Insurance expense		1.91		2.15		2.62		1.57		1.73
Workover and maintenance		4.89		4.93		2.95		4.86		3.85
Direct lease operating expense		15.24		13.87		18.46		13.68		13.43
Total lease operating expense		22.04		20.95		24.03		20.11		19.01
Production taxes		0.35		.28		0.36		0.56		0.36
Gathering and transportation		1.13		1.49		2.33		1.01		0.60
DD&A		22.66		25.81		24.70		24.61		21.44
General and administrative		4.11		4.71		6.96		4.55		6.08
Other – net		1.79		2.10		3.84		1.20		3.22
Total operating expenses		52.08		55.34		62.22		52.04		50.71
Operating income per BOE	$	25.50	$	22.81	$	16.50	$	26.86	$	30.72

Results of Operations

Three Months Ended March 31, 2013 Compared With the Three Months Ended March 31, 2012.

Our consolidated income available for common stockholders for the three months ended March 31, 2013 was $37.6 million or $0.46 diluted income per common share (“per share”) as compared to $82.5 million or $1.04 per share for the three months ended March 31, 2012. This decrease was primarily due to lower crude oil sales, lower operating expenses and a higher effective income tax rate.

Price and Volume Variances

	Three Months Ended March 31,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	2013			2012
	(In thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	106.53		$	109.49		$	(2.96	)		(3	)%	$	(7,622	)
Natural gas sales prices (per Mcf)		3.66			3.06			0.60			20	%		4,837
Total price variance														(2,785	)
Volume Variance
Crude oil sales volumes (MBbls)		2,575			2,856			(281	)		(10	)%		(30,728	)
Natural gas sales volumes (MMcf)		8,042			7,620			422			6	%		1,291
BOE sales volumes (MBOE)		3,916			4,126			(210	)		(5	)%
Percent of BOE from crude oil		66	%		69	%
Total volume variance														(29,437	)
Total price and volume variance													$	(32,222	)

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

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Revenue Variances

	Three Months Ended March 31,				Increase (Decrease)			Percent Increase (Decrease)
	2013		2012
	(In Thousands)
Crude oil	$	274,364	$	312,714	$	(38,350	)		(12	)%
Natural gas		29,410		23,282		6,128			26	%
Total revenues	$	303,774	$	335,996	$	(32,222	)		(10	)%

Revenues

Our consolidated revenues decreased $32.2 million in the third quarter of fiscal 2013 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower crude oil sales volumes as a result of the shut-in caused by Hurricane Isaac coupled with lower crude oil sales prices. The preceding was partially offset by higher natural gas sales prices. 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 decreased revenues by $2.8 million in the third quarter of fiscal 2013. Average crude oil prices, including a $0.42 realized gain per barrel related to hedging activities, decreased $2.96 per barrel in the third quarter of fiscal 2013, resulting in lower revenues of $7.6 million. Average natural gas prices, including a $0.29 realized gain per Mcf related to hedging activities, increased $0.60 per Mcf during the third quarter of fiscal 2013, resulting in higher 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 third quarter of fiscal 2013 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. 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. Crude oil sales volumes decreased 2.8 MBbls per day in the third quarter of fiscal 2013, resulting in lower revenues of $30.7 million. Natural gas sales volumes increased 5.7 MMcf per day in the third quarter of fiscal 2013, resulting in higher revenues of $1.3 million. The decrease in crude oil sales volumes in the third quarter of fiscal 2013 was primarily due to the shut-in of production due to the damage caused by Hurricane Isaac.

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.

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

Costs and Expenses and Other (Income) Expense

	Three Months Ended March 31,												Increase (Decrease) Amount
	2013						2012
	Amount			Per BOE			Amount			Per BOE
	(In Thousands, except per unit amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	7,473		$	1.91		$	7,138		$	1.73		$	335
Workover and maintenance		19,166			4.89			15,885			3.85			3,281
Direct lease operating expense		59,666			15.24			55,424			13.43			4,242
Total lease operating expense		86,305			22.04			78,447			19.01			7,858
Production taxes		1,352			0.35			1,499			0.36			(147	)
Gathering and transportation		4,411			1.13			2,465			0.60			1,946
DD&A		88,727			22.66			88,448			21.44			279
Accretion of asset retirement obligations		7,649			1.95			9,762			2.37			(2,113	)
General and administrative expense		16,092			4.11			25,075			6.08			(8,983	)
(Gain) loss on derivative financial instruments		(632	)		(0.16	)		3,495			0.85			(4,127	)
Total costs and expenses	$	203,904		$	52.08		$	209,191		$	50.71		$	(5,287	)
Other (income) expense
Loss from equity method investees	$	2,587		$	0.66		$	—		$	—		$	2,587
Other income – net		(523	)		(0.13	)		(97	)		(0.02	)		(426	)
Interest expense		27,682			7.07			26,887			6.51			795
Total other (income) expense	$	29,746		$	7.60		$	26,790		$	6.49		$	2,956

Costs and expenses decreased $5.3 million in the third quarter of fiscal 2013. This decrease in costs and expenses was due in part lower general and administrative expense and lower accretion of asset retirement obligations in the third quarter of fiscal 2013 partially offset by higher lease operating expense. Also, the third quarter of fiscal 2013 includes a $0.6 million gain on derivative financial instruments as compared to a $3.5 million loss on derivative financial instruments in the prior year quarter.

Lease operating expense increased $7.9 million in the third quarter of fiscal 2013 compared to the third quarter of fiscal 2012. This increase was primarily due to higher workover and maintenance as a result of Hurricane Issac and higher direct lease operating expense as a result of an increase in the number of properties. Gathering and transportation increased $1.9 million as a result of purchases of additional gathering systems.

Interest expense increased $0.8 million which was principally due to a decrease in debt. On a per unit of production basis, interest expense increased 9%, from $6.51/BOE to $7.07/BOE.

Income Tax Expense

Income tax expense increased $20.9 million in the third quarter of fiscal 2013 compared to the third quarter of fiscal 2012. The effective income tax rate for the third quarter of fiscal 2013 increased from the third quarter of fiscal 2012 from 8.8% to 42.3%. The increase in the tax rate is primarily due to no release of the valuation allowance in the current quarter as compared to the third quarter of fiscal 2012 in which we released the valuation allowance against the current tax on increased U.S. operating income. See Note 10 — Income Taxes of Notes to Consolidated Financial Statements in this Quarterly Report.

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Nine Months Ended March 31, 2013 Compared With the Nine Months Ended March 31, 2012.

Our consolidated income available for common stockholders for the nine months ended March 31, 2013 was $91.4 million or $1.14 per diluted share as compared to consolidated income attributable to common stockholders of $238.5 million or $2.92 per share for the nine months ended March 31, 2012. This decrease was primarily due to lower crude oil production volumes as a result of the damage caused by Hurricane Isaac, higher operating expenses and a higher effective income tax rate.

Price and Volume Variances

	Nine Months Ended March 31,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	2013			2012
	(In thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	105.07		$	105.43		$	(0.36	)		—	%	$	(2,767	)
Natural gas sales prices (per Mcf)		3.85			4.32			(0.47	)		(11	)%		(10,557	)
Total price variance														(13,324	)
Volume Variance
Crude oil sales volumes (MBbls)		7,686			8,241			(555	)		(7	)%		(58,693	)
Natural gas sales volumes (MMcf)		22,583			21,407			1,176			5	%		5,080
BOE sales volumes (MBOE)		11,449			11,809			(360	)		(3	)%
Percent of BOE from crude oil		67	%		70	%
Total volume variance														(53,613	)
Total price and volume variance													$	(66,937	)

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

Revenue Variances

	Nine Months Ended March 31				Increase (Decrease)			Percent Increase
	2013		2012
	(In Thousands)
Crude oil	$	807,518	$	868,978	$	(61,460	)		(7	)%
Natural gas		87,002		92,479		(5,477	)		(6	)%
Total revenues	$	894,520	$	961,457	$	(66,937	)		(7	)%

Revenues

Our consolidated revenues decreased $66.9 million in the first nine months of fiscal 2013 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower crude oil sales volumes and lower natural gas sales prices, partially offset by improved natural gas sales volumes. Revenue variances related to commodity prices and sales volumes are described below.

Price Variances

Lower overall commodity prices decreased revenues by $13.3 million in the first nine months of fiscal 2013. Average natural gas prices, including a $0.56 realized gain per Mcf related to hedging activities, decreased $0.47 per Mcf during the first nine months of fiscal 2013, resulting in decreased revenues of $10.5 million. Average crude oil prices, including a $1.36 realized gain per barrel related to hedging activities, decreased $0.36 per barrel, resulting in decreased revenues of $2.8 million.

Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Lower total sales volumes in the first nine months of fiscal 2013 resulted in decreased revenues of $53.6 million. Crude oil sales volumes decreased 1.9 MBbls per day in the first nine months of fiscal 2013, resulting in decreased revenues of $58.7 million. Natural gas sales volumes increased 4.6 MMcf per day in the first nine months of fiscal 2013, resulting in increased revenues of $5.1 million.

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

Costs and Expenses and Other (Income) Expense

	Nine Months Ended March 31,												Increase (Decrease) Amount
	2013						2012
	Amount			Per BOE			Amount			Per BOE
	(In Thousands, except per unit amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	25,275		$	2.21		$	21,696		$	1.84		$	3,579
Workover and maintenance		49,496			4.32			35,343			2.99			14,153
Direct lease operating expense		179,937			15.72			166,575			14.11			13,362
Total lease operating expense		254,708			22.25			223,614			18.94			31,094
Production taxes		3,765			0.33			4,847			0.41			(1,082	)
Gathering and transportation		18,500			1.62			12,013			1.02			6,487
DD&A		279,378			24.40			260,819			22.09			18,559
Accretion of asset retirement obligations		23,057			2.01			29,253			2.48			(6,196	)
General and administrative expense		59,299			5.18			66,543			5.63			(7,244	)
(Gain) loss on derivative financial instruments		5,755			0.50			(2,506	)		(0.21	)		8,261
Total costs and expenses	$	644,462		$	56.29		$	594,583		$	50.36		$	49,879
Other (income) expense
Loss from equity method investees	$	4,698		$	0.41		$	—		$	—		$	4,698
Other income		(1,425	)		(0.12	)		(121	)		(0.01	)		(1,304	)
Interest expense		81,339			7.10			82,438			6.98			(1,099	)
Total other (income) expense	$	84,612		$	7.39		$	82,317		$	6.97		$	2,295

Costs and expenses increased $49.9 million in the first nine months of fiscal 2013. This increase in costs and expenses was due in part to higher DD&A expense and higher production related expenses partially offset by lower accretion of asset retirement obligations and lower general and administrative expense in the third quarter of fiscal 2013. Also, the first nine months of fiscal 2013 includes a $5.8 million loss on derivative financial instruments as compared to a $2.5 million gain on derivative financial instruments in the comparable prior year period.

DD&A expense increased by $18.6 million in comparing the first nine months of fiscal 2013 to the first nine months of fiscal 2012. DD&A expense increased $26.4 million as a result of an increase in the DD&A rate of $2.31 per BOE, which was partially offset by lower production which decreased DD&A expense by $7.8 million. Lease operating expense increased $31.1 million in the first nine months of fiscal 2013 compared to the first nine months of fiscal 2012. This increase was primarily due to higher workover and maintenance as a result of Hurricane Isaac and higher direct lease operating expense as a result of an increase in the number of properties. Gathering and transportation increased $6.5 million as a result of purchases of additional gathering systems.

Interest expense decreased $1.1 million principally due to a decrease in the overall interest rates. On a per unit of production basis, interest expense increased 2%, from $6.98/BOE to $7.10/BOE.

Income Tax Expense

Income tax expense increased $35.5 million in the first nine months of fiscal 2013 compared to the first nine months of fiscal 2012. The effective income tax rate for the first nine months of fiscal 2013 increased from the first nine months of fiscal 2012 from 10.5% to 39.5%. The increase in the tax rate is primarily due to no release of the valuation allowance in the current first half of fiscal 2013 as compared to the first half of fiscal 2012 in which we released the valuation allowance against the current tax on increased U.S. operating income. See Note 10 — Income Taxes of Notes to Consolidated Financial Statements in this Quarterly Report.

39

Liquidity and Capital Resources

Overview

As of March 31, 2013, we had approximately $30.2 million in cash and cash equivalents on hand and approximately $1,227 million in outstanding long-term debt obligations, net of current maturities.

We have historically funded our operations primarily through available cash, cash flows from operations, borrowings under our revolving credit facility, and the issuance of debt and equity securities. Furthermore, we have historically used cash in the following ways:

• drilling and completing new natural gas and oil wells;

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

• constructing and installing new production infrastructure;

• acquiring additional reserves and producing properties;

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

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

• plugging and abandoning depleted or uneconomic wells; and

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

At March 31, 2013, the principal balance of our revolving credit facility, outstanding tranches of senior notes and other and related maturity dates were as follows:

• Revolving credit facility — $212.8 million — Due December 2014;

• 9.25% Senior Notes — $750 million — Due December 2017;

• 7.75% Senior Notes — $250 million — Due June 2019; and

• 4.14% Promissory Note — $4.9 million — Due October 2017.

We maintain approximately $3.9 million and $40.5 million in bonds issued to BOEM and third parties, respectively, to secure the plugging and abandonment of wells on the outer continental shelf of the Gulf of Mexico as well as the removal of platforms and related facilities, right of way, operator bond and for overweight permit.

Our fiscal 2013 capital budget, excluding acquisitions closed to date and plugging and abandonment costs, is expected to range from $780 million to $810 million ($39 million of plugging and abandonment costs) and we have spent $153.7 million on acquisitions. Exploration and development expenditures during the first nine months of fiscal 2013 were $564 million, which were primarily funded through cash flows from operations. We intend to fund the remaining portion of our capital expenditure program, contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from operations and borrowings under our credit facility. In addition, on May 1, 2013, our Board of Directors approved a stock repurchase program authorizing Energy XXI, Inc., a Delaware subsidiary of the Company (“Energy XXI, Inc.”), to repurchase up to $250 million in value of the Company’s common stock for an extended period of time, in one or more open market transactions. Energy XXI, Inc. intends to fund the share repurchases through borrowings under EGC’s revolving credit facility and repurchased shares will be retained by Energy XXI, Inc., subject to transfer to the Company where they may be retired. Such authorized repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity. We believe our available liquidity will be sufficient to meet our funding requirements through March 31, 2014. However, future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. There can be no assurance that cash flow from operations or other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. If an acquisition opportunity arises, we may also seek to access public markets to issue additional debt and/or equity securities.

40

Operating Activities

Net cash provided by operating activities for the nine months ended March 31, 2013 was $451.5 million as compared to $566.2 million provided by operating activities for the nine months ended March 31, 2012. The decrease was due in part to lower commodity prices and lower production volumes coupled with higher production costs. The nine months ended March 31, 2013 also included significantly lower proceeds from sale of derivative instruments. Changes in operating assets and liabilities increased $51.4 million primarily due to prepaid expenses and other current liabilities.

Investing Activities

Our investments in properties were $717.3 million and $400.4 million for the nine months ended March 31, 2013 and 2012, respectively. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from our operations and borrowings under our credit facility. If an acquisition opportunity arises, we may also access public markets to issue additional debt and/or equity securities. As of April 26, 2013, we had $393 million available for borrowing under our revolving credit facility. Our current borrowing base is $850 million. Our next borrowing base redetermination is scheduled for the fall of 2013 utilizing our June 30, 2013 reserve report. If commodity prices decline and banks lower their internal projections of natural gas and oil prices, it is possible that we will be subject to decreases in our borrowing base availability in the future. We anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for the year ended June 30, 2013. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Cash provided by financing activities was $195 million for the nine months ended March 31, 2013 as compared to cash used in financing activities of $118.6 million for the nine months ended March 31, 2012. During the nine months ended March 31, 2013 proceeds from borrowings net of repayment of debt was $213.5 million. During the nine months ended March 31, 2012, total repayment of debt net of proceeds from borrowings was $111.0 million.

Available Credit

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Multiple events during 2009 through 2012 involving numerous countries and financial institutions impacted liquidity within the capital markets throughout the United States and around the world. Despite efforts by the U.S. Treasury Department and banking regulators in the United States, Europe and other nations around the world to provide liquidity and stability to the financial sector, capital markets have remained somewhat constrained. As a result, we expect that our ability to raise debt and equity and the terms on which we can raise capital may be somewhat restricted and will be dependent upon the condition of the capital markets.

Notwithstanding periodic weakness in the U.S. credit markets, we expect that our available liquidity is sufficient to meet our operating and capital requirements through March 31, 2013. Additionally, our credit facility is comprised of a syndicate of large domestic and international banks, with no single lender providing more than 10% of the overall commitment amount.

Contractual Obligations

Information about contractual obligations at March 31, 2013 did not change materially, other than as disclosed in Note 6 — Long-Term Debt and Note 16 — Commitments and Contingencies of Notes to Consolidated Financial Statements in this Quarterly Report and from the disclosures in Item 7 of our 2012 Annual Report.

41

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 — Organization and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements included in our 2012 Annual Report.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Note 2 — Recent Accounting Pronouncements of Notes to Consolidated Financial Statements in this Quarterly Report.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

General

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2012 Annual Report.

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at March 31, 2013, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

Credit Risk

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries and to a lesser extent our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we reduce credit risk.

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue.

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 also 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 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

42

any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of, 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.

At March 31, 2013, our natural gas contracts outstanding had an asset position of $4.8 million. A 10% increase in natural gas prices would reduce the fair value by approximately $1.7 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $0.9 million. Also, at March 31, 2013, our crude oil contracts outstanding had an asset position of $35.6 million. A 10% increase in crude oil prices would reduce the fair value by approximately $52.7 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $63.4 million. These fair value changes assume volatility based on prevailing market parameters at March 31, 2013. See Note 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

Our ultimate realized gain or loss with respect to commodity price fluctuations will depend on the future exposures that arise during the period, our hedging strategies at the time and commodity prices at the time.

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we have utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the quarter ended September 30, 2011, the Company began utilizing ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio as we believe that the Brent prices are more reflective of our realized crude oil production pricing (HLS). Thus by modifying our hedge portfolio to include Brent benchmarks for crude hedging, we aim to more appropriately manage our exposure and manage our price risk.

  Interest Rate Risk

Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We consider our interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 83 percent of the Company’s debt. As of March 31, 2013, total debt included $212.0 million of floating-rate debt. As a result, our period end interest costs will fluctuate based on short-term interest rates on approximately 17 percent of our total debt outstanding as of March 31, 2013. A 10 percent change in floating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $13,000. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. However, to reduce our future exposure to changes in interest rates, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.

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

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and our principal financial officer, we evaluated the effectiveness of the design and operation of our 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”)) as of the end of the period covered by this Quarterly Report.

43

Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of the end of the period covered by this Quarterly Report.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our quarterly period ended March 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

44

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our common stock, please refer to the section entitled “Item 1A. Risk Factors” in our 2012 Annual Report. There has been no material change in the risk factors set forth in our 2012 Annual Report.

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

None

ITEM 3. Defaults upon Senior Securities

None

ITEM 4. Mine Safety Disclosures

Not applicable

ITEM 5. Other Information

None

ITEM 6. Exhibits

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this Quarterly Report, and such Exhibit Index is incorporated herein by reference.

45

SIGNATURES

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

ENERGY XXI (BERMUDA) LIMITED

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

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

Date: May 6, 2013

46

EXHIBIT INDEX

Exhibit Number	Exhibit Title	Incorporated by Reference to the Following
3.1	Altered Memorandum of Association of Energy XXI (Bermuda) Limited	3.1 to the Company’s Form 8-K filed on November 9, 2011
3.2	Bye-Laws of Energy XXI (Bermuda) Limited	3.2 to the Company’s Form 8-K filed on November 9, 2011
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Furnished herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Furnished herewith
32.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith
101.INS	XBRL Instance Document	Furnished herewith
101.SCH	XBRL Schema Document	Furnished herewith
101.CAL	XBRL Calculation Linkbase Document	Furnished herewith
101.DEF	XBRL Definition Linkbase Document	Furnished herewith
101.LAB	XBRL Label Linkbase Document	Furnished herewith
101.PRE	XBRL Presentation Linkbase Document	Furnished herewith

47

EX-31.1

Exhibit 31.1

CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, John D. Schiller, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2013 of Energy XXI (Bermuda) Limited (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2013

/S/ JOHN D. SCHILLER, JR.

John D. Schiller, Jr.
Chief Executive Officer

EX-32.1

Exhibit 31.2

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, David West Griffin, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2013 of Energy XXI (Bermuda) Limited (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2013

/S/ DAVID WEST GRIFFIN

David West Griffin
Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF
CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER
UNDER SECTION 906 OF THE
SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with this quarterly report on Form 10-Q for the quarter ended March 31, 2013 of Energy XXI (Bermuda) Limited (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), John D. Schiller, Jr., Chief Executive Officer of the Company and David West Griffin, Chief Financial Officer of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) the report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2013	/S/ JOHN D. SCHILLER, JR. John D. Schiller, Jr. Chief Executive Officer

Date: May 6, 2013	/S/ DAVID WEST GRIFFIN David West Griffin Chief Financial Officer

XML

Acquisitions (Purchase Price Allocations To The Assets Acquired And Liabilities Assumed) (Details) (USD $) In Thousands, unless otherwise specified	Oct. 17, 2012 Gulf Of Mexico Interests [Member]	Nov. 07, 2012 Dynamic Interests [Member]	Jan. 17, 2013 McMoran Interest [Member]	Mar. 14, 2013 Roda Interest [Member]
Restructuring Cost and Reserve [Line Items]
Oil and natural gas properties - evaluated	$ 11,088	$ 1,716	$ 63,186	$ 33,615
Oil and natural gas properties - unevaluated	27,721	6,571	17,184
Net working capital			12	500
Asset retirement obligations	(5,353)	(1,090)	(382)	(115)
Cash paid	$ 33,456	$ 7,197	$ 80,000	$ 34,000

XML

Stockholders Equity (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended			9 Months Ended		12 Months Ended	9 Months Ended	12 Months Ended
	May 01, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2013	Mar. 31, 2013 7.25% Convertible Perpetual Preferred Stock [Member]	Jun. 30, 2012 7.25% Convertible Perpetual Preferred Stock [Member]	Mar. 31, 2013 5.625% Convertible Perpetual Preferred Stock [Member]	Jun. 30, 2012 5.625% Convertible Perpetual Preferred Stock [Member]	Mar. 31, 2013 Minimum [Member] 5.625% Convertible Perpetual Preferred Stock [Member]	Mar. 31, 2013 Maximum [Member] 5.625% Convertible Perpetual Preferred Stock [Member]
Class of Stock [Line Items]
Dividends declared date	May 01, 2013
Cash dividend per share	$ 0.12	$ 0.07	$ 0.07	$ 0.07
Dividends payment record date	May 31, 2013
Dividends payment date	Jun. 14, 2013	Mar. 15, 2013	Dec. 14, 2012	Sep. 14, 2012
Preferred stock, shares authorized				7,500,000	7,500,000
Dividend payment terms					Dividends on both the 5.625% Perpetual Convertible Preferred Stock ("5.625% Preferred Stock") and the 7.25% Perpetual Convertible Preferred Stock ("7.25% Preferred Stock") are payable quarterly in arrears on each March 15, June 15, September 15 and December 15 of each year.
Percentage of market value of shares at which dividend paid in shares of common stock shall be valued					95.00%
Preferred stock dividend rate						7.25%	7.25%	5.625%	5.625%
Conversion of preferred stock to common stock, shares								929
Common stock shares issued as a result of conversion of Preferred stock								9,183
Stated conversion rate of common shares per preferred share										9.8578	9.899

XML

Derivative Financial Instruments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	48 Months Ended	9 Months Ended			3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2013	Mar. 31, 2013 Net Of Tax	Mar. 31, 2013 West Texas Intermediate [Member]	Mar. 31, 2013 Heavy Louisiana Sweet [Member]	Mar. 31, 2013 June 30, 2013 [Member]	Mar. 31, 2013 June 30, 2013 [Member]	Mar. 31, 2013 September 30, 2013 [Member]	Mar. 31, 2013 September 30, 2013 [Member]	Mar. 31, 2013 December 31, 2013 [Member]	Mar. 31, 2013 Puts [Member]
Derivative [Line Items]
Fixed price commodity risk per barrel-HLS/WTI basis differential				1	30
Amount expected to be reclassified from other comprehensive income to income	$ 15.9		$ 10.3				$ 4.5		$ 4.5
Cash proceeds against certain hedge positions		181.1
Remaining balance in accumulated OCI	13.5	13.5
Deferred revenue											2.2
Remaining balance of deferred reveune											2
Deferred revenue, recognized						$ 0.6		$ 0.7		$ 0.7

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Supplemental Cash Flow Information (Supplemental Cash Flow Information) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 3,402	$ 4,698	$ 50,591	$ 56,721
Cash paid for income taxes	$ 4,056		$ 7,017

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Notes Payable (Narrative) (Details) (USD $)	1 Months Ended		1 Months Ended
	Jul. 31, 2012 Notes Payable [Member]	Mar. 31, 2013 Notes Payable [Member]	Nov. 30, 2012 AFCO Credit Corporation [Member]	May 31, 2012 AFCO Credit Corporation [Member]	Mar. 31, 2013 AFCO Credit Corporation [Member]
Debt Instrument [Line Items]
Face value of note payable	$ 3,600,000		$ 600,000	$ 26,000,000
Rate of interest on notes payable	1.667%		1.774%	1.556%
Notes payable outstanding		$ 700,000			$ 300,000
Maturity date	May 01, 2013		Oct. 23, 2013	Dec. 26, 2012

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Employee Benefit Plans (Tables)

9 Months Ended

Mar. 31, 2013

Employee Benefit Plans [Abstract]

Compensation Expense Recognized

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Restricted Stock Units	$	1,941	$	6,897	$	9,668	$	17,032
Performance Units		231		10,055		13,086		27,007
Total compensation expense recognized	$	2,172	$	16,952	$	22,754	$	44,039

Compensation Expense Recognized And Shares Issued Under Employee Stock Purchase Plan

	Three Months Ended   March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Compensation expense	$	221	$	215	$	598	$	516
Shares issued		—		—		27,608		21,015

Summary Of Stock Option Activity And Related Information

	2013			2012
	Shares Under Option		Weighted Ave. Exercise Price	Shares Under Option			Weighted Ave. Exercise Price
Beginning balance		—			100,000		$	17.50
Vested		—			(100,000	)		17.50
Ending balance		—			—

Defined Contribution Plans

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Profit Sharing Plan	$	(481)	$	(49)	$	1,712	$	1,756
401(k) Plan		1,587		1,360		2,948		2,866
Total contributions	$	1,106	$	1,311	$	4,660	$	4,622

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Employee Benefit Plans (Narrative) (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2008	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Recognized compensation expense		$ 2,172,000	$ 16,952,000	$ 22,754,000	$ 44,039,000
Employee Stock Purchase Plan [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Stock issued		208,988		208,988	277,980
Discount from the lower of the common stock closing price on the first or last day of the period				15.00%
Stock Options [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Recognized compensation expense		0	0	0	58,000
Stock Options granted to certain officers	300,000
Stock Options granted to certain officers, exercise price	$ 17.50
Option vesting period	3 years
Stock options vested and exercised		100,000		100,000
Stock options vested and not exercised		200,000		200,000
Performance Units [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Share based payment awards, vesting period				3 years
Percentage of Time Based Performance units award out of the total performance units awarded				25.00%
Percentage of total shareholder return TSR Performance Based Units				75.00%
Performance based unit award, common stock paid		50.00%		50.00%
Unvested stock units outstanding		5,170,042		5,170,042
Recognized compensation expense		231,000	10,055,000	13,086,000	27,007,000
Restricted Stock Units (RSUs) [Member]
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Share based payment awards, vesting period				3 years
Unvested stock units outstanding		886,626		886,626
Recognized compensation expense		$ 1,941,000	$ 6,897,000	$ 9,668,000	$ 17,032,000

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Subsequent Events

9 Months Ended

Mar. 31, 2013

Subsequent Events [Abstract]

Subsequent Events

Note 19 — Subsequent Events

EGC entered into the Fourth and Fifth Amendments to the First Lien Credit Agreement on April 9, 2013 and May 1, 2013, respectively See Note 6 – Long-Term Debt of Notes to Consolidated Financial Statements in this Quarterly Report.

On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement.  See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

On May 1, 2013, our board of directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on June 14, 2013 to shareholders of record on May 31, 2013.

On May 1, 2013, our Board of Directors approved a stock repurchase program authorizing Energy XXI, Inc., a Delaware subsidiary of the Company (“Energy XXI, Inc.”), to repurchase up to $250 million in value of the Company’s common stock for an extended period of time in one or more open market transactions. The Company also announced that in connection with the repurchase program, the Board of Directors has also approved a 10b5-1 plan, allowing Energy XXI, Inc. to repurchase the Company’s shares at times when it otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods.  Energy XXI, Inc. intends to fund the share repurchases through borrowings under EGC’s revolving credit facility and repurchased shares will be retained by Energy XXI, Inc., subject to transfer to the Company where they may be retired.  Such authorized repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity.

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Derivative Financial Instruments (Fair Values Of Derivative Instruments in Consolidated Balance Sheet) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2012
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 85,467	$ 170,955
Liability Derivatives	45,106	92,962
Designated As Hedging Instrument [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	13,622	34,462
Designated As Hedging Instrument [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	26,896	58,229
Designated As Hedging Instrument [Member] | Current Asset [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	37,233	66,716
Designated As Hedging Instrument [Member] | Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	43,294	103,462
Not Designated As Hedging Instrument [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	4,444	83
Not Designated As Hedging Instrument [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	144	188
Not Designated As Hedging Instrument [Member] | Current Asset [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	4,621	326
Not Designated As Hedging Instrument [Member] | Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 319	$ 451

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Long-Term Debt (Narrative) (Details) (USD $)						0 Months Ended	9 Months Ended	12 Months Ended			0 Months Ended	9 Months Ended			9 Months Ended	12 Months Ended			0 Months Ended	9 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Revolving Credit Facility [Member]	Oct. 19, 2012 Revolving Credit Facility [Member]	Mar. 31, 2013 Revolving Credit Facility [Member] Minimum [Member]	Mar. 31, 2013 Revolving Credit Facility [Member] Maximum [Member]	Dec. 17, 2010 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2013 9.25 Percent Senior Notes Due 2017 [Member]	Jun. 30, 2012 9.25 Percent Senior Notes Due 2017 [Member]	Jul. 08, 2011 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2013 9.25 Percent Senior Notes Due 2017 [Member] Maximum [Member]	Feb. 25, 2011 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2013 7.75 Percent Senior Notes Due 2019 [Member]	Jul. 11, 2011 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2013 7.75 Percent Senior Notes Due 2019 [Member] Maximum [Member]	Mar. 31, 2013 4.14% Promissory Note Due 2017 [Member]	Jun. 30, 2012 4.14% Promissory Note Due 2017 [Member]	Mar. 31, 2013 Derivative Instruments Premium Financing [Member]	Jun. 30, 2012 Derivative Instruments Premium Financing [Member]	Oct. 04, 2011 First Amendment [Member] Distribution Baskets [Member]	Mar. 31, 2013 Fourth Amendment As Of April 9, 2013 [Member] Revolving Credit Facility [Member]	Mar. 31, 2013 Fourth Amendment As Of April 9, 2013 [Member] Revolving Credit Facility [Member] Maximum [Member]	Mar. 31, 2013 Fifth Amendment As Of May 1, 2013 [Member] Minimum [Member]	Mar. 31, 2013 Fifth Amendment As Of May 1, 2013 [Member] Maximum [Member]	Mar. 31, 2013 Market Rate Applies [Member] Revolving Credit Facility [Member] Minimum [Member] LIBOR [Member]	Mar. 31, 2013 Market Rate Applies [Member] Revolving Credit Facility [Member] Minimum [Member] Federal Funds Rate [Member]	Mar. 31, 2013 Market Rate Applies [Member] Revolving Credit Facility [Member] Maximum [Member] LIBOR [Member]	Mar. 31, 2013 Market Rate Applies [Member] Revolving Credit Facility [Member] Maximum [Member] Federal Funds Rate [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 925,000,000																		$ 1,700,000,000
Debt Maturity Date						Dec. 15, 2017	Dec. 15, 2017	Dec. 15, 2017			Jun. 15, 2019				Oct. 30, 2017	Oct. 30, 2017				Apr. 09, 2018
Applicable margin above LIBOR or the base rate																								1.75%	0.75%	2.75%	1.75%
Percentage of secured mortgage				85.00%
Expected dividend payments in any calendar year					17,000,000																50,000,000		350,000,000
Required percentage of consolidated net income																			50.00%
Required limit of facility to cash distribution																			70,000,000
Leverage ratio					3.5
Interest rate coverage ratio				3.0
Current ratio					1.0
Current borrowing capacity			825,000,000																	850,000,000		150,000,000
Face value of senior notes						750,000,000					250,000,000				5,500,000
Debt instrument, stated interest rate						9.25%	9.25%	9.25%			7.75%	7.75%			4.14%
Exchanged aggregate principal amount									749,000,000				250,000,000
Remaining face value						1,000,000
Percentage of call price of the par value of the note							104.625%					103.875%
Starting date							Dec. 15, 2014					Jun. 15, 2015
Latest date							Dec. 15, 2016					Jun. 15, 2017
Redemption rate										35.00%				35.00%
Percentage of unsecured senior note redemption price							109.25%					107.75%
Senior unsecured notes, redemption term							Dec. 15, 2013					Jun. 15, 2014			Oct. 30, 2017
Underwriting and direct offering costs							15,400,000					3,100,000
Debt instrument, fair value							848,900,000					271,300,000
Debt instrument, monthly payment															52,000
Number of lump-sum payment															1
Lump sum payments															3,300,000
Derivative instruments discount rate																	2.50%	2.50%
Letter of credit	225,300,000																31,400,000	17,400,000
Unsecured indebtedness, maximum		250,000,000																		750,000,000
Unsecured indebtedness reduction aggregate, reduction percentage																				25.00%
Unsecured indebtedness, minimum, related to reduction percentage																				250,000,000
Percentage of borrowing base																						15.00%
Total aggregate distribution, limit																							$ 70,000,000
Percentage of consolidated net income, limit																							50.00%

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Prepayments And Accrued Liabilities (Tables)

9 Months Ended

Mar. 31, 2013

Prepayments And Accrued Liabilities [Abstract]

Components of Prepayments and Accrued Liabilities

	March 31,	June 30,
	2013	2012
Prepaid expenses and other current assets
Advances to joint interest partners	$ 3,059	$ 12,966
Insurance	6,801	30,515
Inventory	4,127	4,849
Royalty deposit	1,961	2,443
Short-term stock investment	23	8,786
Other	6,823	3,470
Total prepaid expenses and other current assets	$ 22,794	$ 63,029
Accrued liabilities
Advances from joint interest partners	$ 10,264	$ 301
Employee benefits and payroll	29,132	53,541
Interest	28,037	3,721
Accrued hedge payable	4,228	136
Undistributed oil and gas proceeds	46,757	54,484
Other	3,146	6,635
Total accrued liabilities	$ 121,564	$ 118,818

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Derivative Financial Instruments (Schedule Of Cash Flow Hedging Relationship Of Derivative Instruments) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss,net of tax (Effective Portion)	$ 5,964	$ 39,757	$ 43,482	$ (52,837)
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)	(4,657)	(1,349)	(18,526)	(16,658)
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)	(816)	3,388	3,800	1,713
Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)	(4,657)	(1,349)	(18,526)	(16,658)
(Gain) Loss on Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)	(816)	3,388	3,800	1,713
Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss,net of tax (Effective Portion)	$ 5,964	$ 39,757	$ 43,482	$ (52,837)

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Fair Value Of Financial Instruments (Changes To Level 3 Financial Instruments) (Details) (Performance Stock Unit, USD $) In Thousands, unless otherwise specified	9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Performance Stock Unit
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Balance at beginning of Period	$ 22,855	$ 20,305
Vested	(23,161)	(23,807)
Grants and changes in fair value charged to general and administrative expense	10,264	23,320
Balance at end of period	$ 9,958	$ 19,818

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Employee Benefit Plans (Annual Employer Contribution) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Profit Sharing Plan Contribution [Line Items]
Employer contribution plan cost	$ 1,106	$ 1,311	$ 4,660	$ 4,622
Profit Sharing Plan [Member]
Profit Sharing Plan Contribution [Line Items]
Employer contribution plan cost	(481)	(49)	1,712	1,756
401 (k) Plan [Member]
Profit Sharing Plan Contribution [Line Items]
Employer contribution plan cost	$ 1,587	$ 1,360	$ 2,948	$ 2,866

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Mar. 31, 2013	Jun. 30, 2012
Asset Retirement Obligation [Abstract]
Balance at June 30, 2012	$ 301,415
Liabilities acquired	6,940
Liabilities incurred	11,605
Liabilities settled	(29,570)
Accretion expense	23,057
Total balance at March 31, 2013	313,447
Less current portion	30,130	34,457
Long-term balance at March 31, 2013	$ 283,317	$ 266,958

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Acquisitions

9 Months Ended

Mar. 31, 2013

Acquisitions [Abstract]

Acquisitions

Note 3 – Acquisitions

ExxonMobil oil and gas properties interests acquisition

    On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“Exxon”) for a total cash consideration of approximately $33.5 million.  The GOM Interests cover 5,000 gross acres on Vermilion Block 164(“VM 164”).  We are the operator of these properties.  In addition to acquiring the GOM Interests, we entered into a joint venture agreement with Exxon to explore for oil and gas on nine contiguous blocks adjacent to VM 164 in shallow waters on the Gulf of Mexico shelf.  We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012.  Our total capital commitment for the joint venture in calendar year 2013 is estimated at $75 million, assuming successful completion of two earning wells. 

    Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income.  The acquisition of the GOM interests was accounted for under the purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

Oil and natural gas properties – evaluated	$ 11,088
Oil and natural gas properties – unevaluated	27,721
Asset retirement obligations	(5,353)
Cash paid	$ 33,456

Dynamic Offshore oil and gas properties interests acquisition

    On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VM 164 for approximately $7.2 million. 

    Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income.  The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

Oil and natural gas properties – evaluated	$ 1,716
Oil and natural gas properties – unevaluated	6,571
Asset retirement obligations	(1,090)
Cash paid	$ 7,197

McMoRan oil and gas properties interests acquisition

    On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin  field (“Bayou Carlin  Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $80 million.  This acquisition is effective January 1, 2013.  We are the operator of these properties. 

    Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income.  The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

Oil and natural gas properties – evaluated	$ 63,186
Oil and natural gas properties – unevaluated	17,184
Net working capital	12
Asset retirement obligations	(382)
Cash paid	$ 80,000

Roda oil and gas properties interests acquisition

    On March 14, 2013, we acquired 100% of the interests (“Roda Interests”) held by Roda Drilling LP (“Roda”) in the Bayou Carlin  field for $34 million. This acquisition is effective January 1, 2013.

    Revenues and expenses related to the Roda Interests from the closing date of March 14, 2013 are included in our consolidated statements of income.  The acquisition of the Roda Interests was accounted for under the purchase method of accounting.  Transaction, transition and integration costs associated with this acquisition were expensed as incurred.  The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

Oil and natural gas properties – evaluated	$ 33,615
Net working capital	500
Asset retirement obligations	(115)
Cash paid	$ 34,000

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

Apache Joint Venture

    On February 1, 2013, we entered into an Exploration Agreement (“Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central Gulf of Mexico Shelf.  We have a 25% participation interest in the Agreement, which expires on February 1, 2018. 

    The area of mutual interest (“AMI”) under this agreement includes several salt domes within a 135 block area.  Our share of cost to acquire seismic data over a two year seismic shoot phase is currently estimated to be approximately $37.5 million.  We have presently consented to participate in drilling one well and have an option to participate in two other wells under the current drilling program.

    As of March 31, 2013, we paid consideration of approximately $2.5 million, being our participation interest, to Apache for non-producing primary-term leases.

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Related Party Transactions (Narrative) (Details) (USD $)			9 Months Ended
	Mar. 31, 2013	Jun. 30, 2012	Mar. 31, 2013 Energy XXI M21K LLC [Member]	Feb. 23, 2012 Energy XXI M21K LLC [Member]	Mar. 31, 2013 Ping Energy XXI Limited
Related Party Transaction [Line Items]
Percentage of investments under the equity method			20.00%	20.00%	49.00%
Amount of line of credit			$ 100,000,000
Asset retirement obligation	313,447,000	301,415,000	65,000,000
Other Liabilities			1,800,000
Due from related party			6,300,000
Due from related party, commitment period			3 years
Amount received from related party			$ 1,200,000

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Long-Term Debt (Schedule Of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified								0 Months Ended	9 Months Ended	12 Months Ended	0 Months Ended			9 Months Ended	12 Months Ended
	Mar. 31, 2013	Jun. 30, 2012	Mar. 31, 2013 Revolving Credit Facility [Member]	Mar. 31, 2013 Derivative Instruments Premium Financing [Member]	Jun. 30, 2012 Derivative Instruments Premium Financing [Member]	Mar. 31, 2013 Capital Lease Obligations	Jun. 30, 2012 Capital Lease Obligations	Dec. 17, 2010 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2013 9.25 Percent Senior Notes Due 2017 [Member]	Jun. 30, 2012 9.25 Percent Senior Notes Due 2017 [Member]	Feb. 25, 2011 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2013 7.75 Percent Senior Notes Due 2019 [Member]	Jun. 30, 2012 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2013 4.14% Promissory Note Due 2017 [Member]	Jun. 30, 2012 4.14% Promissory Note Due 2017 [Member]
Debt Instrument [Line Items]
Total debt	$ 1,250,572	$ 1,018,344	$ 212,831	$ 31,387	$ 17,387	$ 1,065	$ 957		$ 750,000	$ 750,000		$ 250,000	$ 250,000	$ 5,289
Less current maturities	23,428	4,284
Total long-term debt	$ 1,227,144	$ 1,014,060
Debt instrument, stated interest rate								9.25%	9.25%	9.25%	7.75%	7.75%		4.14%
Debt Maturity Date								Dec. 15, 2017	Dec. 15, 2017	Dec. 15, 2017	Jun. 15, 2019			Oct. 30, 2017	Oct. 30, 2017

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Long-Term Debt (Tables)

9 Months Ended

Mar. 31, 2013

Long-Term Debt [Abstract]

Schedule Of Long-Term Debt

	March 31,	June 30,
	2013	2012
Revolving credit facility	$ 212,831	$—
9.25% Senior Notes due 2017	750,000	750,000
7.75% Senior Notes due 2019	250,000	250,000
4.14% Promissory Note due 2017	5,289	—
Derivative instruments premium financing	31,387	17,387
Capital lease obligation	1,065	957
Total debt	1,250,572	1,018,344
Less current maturities	23,428	4,284
Total long-term debt	$ 1,227,144	$ 1,014,060

Maturities Of Long-Term Debt

Twelve Months Ended March 31,
2014	$ 23,428
2015	222,331
2016	813
2017	465
2018	753,535
Thereafter	250,000
Total	$ 1,250,572

Interest Expense

	Three Months Ended March 31,		Nine Months Ended March 31,
	2013	2012	2013	2012
Revolving credit facility	$ 3,330	$ 2,201	$ 8,185	$ 7,291
9.25% Senior Notes due 2017	17,343	17,344	52,031	52,031
7.75% Senior Notes due 2019	4,843	4,843	14,531	14,531
Amortization of debt issue cost - Revolving credit facility	1,261	1,238	3,762	3,645
Amortization of debt issue cost – 9.25% Senior Notes due 2017	552	552	1,655	1,655
Amortization of debt issue cost – 7.75% Senior Notes due 2019	97	97	291	291
Derivative instruments financing and other	256	612	884	2,994
	$ 27,682	$ 26,887	$ 81,339	$ 82,438

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Property And Equipment (Tables)

9 Months Ended

Mar. 31, 2013

Property And Equipment [Abstract]

Schedule Of Property And Equipment

	March 31,	June 30,
	2013	2012
Oil and gas properties
Proved properties	$ 4,982,071	$ 4,375,984
Less: Accumulated depreciation, depletion, amortization and impairment	2,373,186	2,096,531
Proved properties	2,608,885	2,279,453
Unproved properties	539,354	418,760
Oil and gas properties	3,148,239	2,698,213
Other property and equipment	31,273	22,132
Less: Accumulated depreciation	15,159	12,599
Other property and equipment	16,114	9,533
Total property and equipment – net of accumulated depreciation, depletion, amortization     and impairment	$ 3,164,353	$ 2,707,746

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Supplemental Cash Flow Information (Non-cash Investing And Financing Activities) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Supplemental Cash Flow Information [Abstract]
Financing of insurance premiums	$ (1,266)	$ (8,558)	$ (21,131)	$ (19,215)
Derivative instruments premium financing	12,780	15,557	14,001	12,869
Preferred stock dividends	(53)	(138)	(593)	(138)
Additions to property and equipment by recognizing asset retirement obligations	$ 1,816	$ 700	$ 11,605	$ 2,037

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Long-Term Debt (Maturities Of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2012
Long-Term Debt [Abstract]
2014	$ 23,428
2015	222,331
2016	813
2017	465
2018	753,535
Thereafter	250,000
Total debt	$ 1,250,572	$ 1,018,344

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Asset Retirement Obligations (Tables)

9 Months Ended

Mar. 31, 2013

Asset Retirement Obligation [Abstract]

Changes In Asset Retirement Obligations

Balance at June 30, 2012	$ 301,415
Liabilities acquired	6,940
Liabilities incurred	11,605
Liabilities settled	(29,570)
Accretion expense	23,057
Total balance at March 31, 2013	313,447
Less current portion	30,130
Long-term balance at March 31, 2013	$ 283,317

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Derivative Financial Instruments (Tables)

9 Months Ended

Mar. 31, 2013

Fair Values Of Derivative Instruments In Consolidated Balance Sheet

	Asset Derivative Instruments								Liability Derivative Instruments
	March 31, 2013				June 30, 2012				March 31, 2013				June 30, 2012
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments		Current	$	37,233		Current	$	66,716		Current	$	13,622		Current	$	34,462
		Non-Current		43,294		Non-Current		103,462		Non-Current		26,896		Non-Current		58,229
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		4,621		Current		326		Current		4,444		Current		83
		Non-Current		319		Non-Current		451		Non-Current		144		Non-Current		188
Total			$	85,467			$	170,955			$	45,106			$	92,962

Schedule Of Derivative Instruments Gain (Loss) In Statement Of Financial Performance

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Location of (Gain)Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(1,084)	$	3,009	$	(10,455)	$	2,576
Natural gas sales		(2,340)		(4,128)		(12,879)		(23,528)
Total cash settlements		(3,424)		(1,119)		(23,334)		(20,952)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instrumentsIneffective portion of commodity derivative instruments		(816)		3,388		3,800		1,713
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		(41)		23		1,832		(5,001)
Unrealized mark to market (gain) loss		225		84		123		782
Total (gain) loss on derivative financial instruments		(632)		3,495		5,755		(2,506)
Total gain	$	(4,056)	$	2,376	$	(17,579)	$	(23,458)

Schedule Of Cash Flow Hedging Relationship Of Derivative Instruments

Location of (Gain)/Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Three Months Ended March 31, 2013
Commodity Derivative Instruments	$	5,964
Revenues			$	(4,657)
(Gain) loss on derivative financial instruments					$	(816)
Total	$	5,964	$	(4,657)	$	(816)
Three Months Ended March 31, 2012
Commodity Derivative Instruments	$	39,757
Revenues			$	(1,349)
(Gain) loss on derivative financial instruments					$	3,388
Total	$	39,757	$	(1,349)	$	3,388
Nine Months Ended March 31, 2013
Commodity Derivative Instruments	$	43,482
Revenues			$	(18,526)
(Gain) loss on derivative financial instruments					$	3,800
Total	$	43,482	$	(18,526)	$	3,800
Nine Months Ended March 31, 2012
Commodity Derivative Instruments	$	(52,837)
Revenues			$	(16,658)
(Gain) loss on derivative financial instruments					$	1,713
Total	$	(52,837)	$	(16,658)	$	1,713

Crude Oil [Member]

Schedule Of Derivative Positions

As of March 31, 2013, we had the following net open crude oil derivative positions:

					Weighted Average Contract Price
					Swaps	Collars/Put Spread
Period	Type of Contract	Index	Volumes (MBbls)		Fixed Price	Sub Floor	Floor	Ceiling
April 2013 - December 2013	Three-Way Collars	Oil-Brent-IPE	2,570	(1)		$ 85.72	$ 105.72	$ 126.72
April 2013 - December 2013	Put Spreads	Oil-Brent-IPE	1,830			87.00	106.25
April 2013 - December 2013	Three-Way Collars	NYMEX-WTI	1,375			70.00	90.00	136.32
April 2013 - December 2013	Collars	NYMEX-WTI	963				73.57	105.63
April 2013 - December 2013	Swaps	NYMEX-WTI	138		$ 86.60
April 2013 - December 2013	Swaps	NYMEX-WTI	(138)		88.20
January 2014 - December 2014	Three-Way Collars	Oil-Brent-IPE	2,373			68.08	88.08	130.88
January 2014 - December 2014	Collars	Oil-Brent-IPE	730				90.00	108.38
January 2014 - December 2014	Three-Way Collars	NYMEX-WTI	3,650			70.00	90.00	137.14
January 2015 - December 2015	Three-Way Collars	Oil-Brent-IPE	1,825			72.00	92.00	111.56

(1) The Oil-Brent-IPE three-way collars for the period from April 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

Natural Gas [Member]

Schedule Of Derivative Positions

As of March 31, 2013, we had the following open natural gas derivative positions:

				Weighted Average Contract Price
				Collars/Call Spread
Period	Type of Contract	Index	Volumes (MMBtu)	Sub Floor	Floor	Ceiling
April 2013 - December 2013	Three-Way Collars	NYMEX-HH	8,250	$ 4.07	$ 4.93	$ 5.87
January 2014 – December 2014	Call Spread	NYMEX-HH	913	4.20	5.00

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Recent Accounting Pronouncements

9 Months Ended

Mar. 31, 2013

Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

Note 2 – Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-05: Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. The update is intended to increase the prominence of other comprehensive income in the financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011, with early adoption permitted. We adopted ASU 2011-05 on June 30, 2012 and the adoption had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12: Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”) . ASU 2011-12 defers the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. As part of this update, the FASB did not defer the requirement to report comprehensive income either in a single continuous statement or in two separate but consecutive financial statements. ASU 2011-12 is effective for annual periods beginning after December 15, 2011.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

In February 2013, the FASB issued Accounting Standards Update No.  2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”).   ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of other comprehensive income (“AOCI”) included in equity in one place.  Total changes in AOCI by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We do not expect the adoption ASU 2013-02 to have any effect on our consolidated financial position, results of operations or cash flows, other than presentation.

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Mar. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

	Three Months Ended      March 31,		Nine Months Ended      March 31,
	2013	2012	2013	2012
Cash paid for interest	$ 3,402	$ 4,698	$ 50,591	$ 56,721
Cash paid for income taxes	4,056	—	7,017	—

Non-Cash Investing and Financing Activities

	Three Months Ended March 31,		Nine Months Ended      March 31,
	2013	2012	2013	2012
Financing of insurance premiums	$ (1,266)	$ (8,558)	$ (21,131)	$ (19,215)
Derivative instruments premium financing	12,780	15,557	14,001	12,869
Preferred stock dividends	(53)	(138)	(593)	(138)
Additions to property and equipment by recognizing asset retirement obligations	1,816	700	11,605	2,037

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Property And Equipment (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2012
Oil and gas properties
Proved properties	$ 4,982,071	$ 4,375,984
Less: Accumulated depreciation, depletion, amortization and impairment	2,373,186	2,096,531
Proved properties	2,608,885	2,279,453
Unproved properties	539,354	418,760
Oil and gas properties	3,148,239	2,698,213
Other property and equipment	31,273	22,132
Less: Accumulated depreciation	15,159	12,599
Other property and equipment, net	16,114	9,533
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	$ 3,164,353	$ 2,707,746

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Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Mar. 31, 2013
Income Taxes [Line Items]
Estimated annual effective tax rate	39.50%
U.S statutory income tax rate	35.00%
U.S. withholding tax rate on any interest payments	30.00%
Accrued withholding tax obligation	$ 10.4
Valuation allowance amount	30.0
Cash withholding tax payment	3.9
Maximum [Member]
Income Taxes [Line Items]
Estimated income tax payment	$ 5

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2012
Current Assets
Cash and cash equivalents	$ 30,229	$ 117,087
Accounts receivable
Oil and natural gas sales	138,522	126,107
Joint interest billings	9,260	3,840
Insurance and other	4,773	5,420
Prepaid expenses and other current assets	22,794	63,029
Derivative financial instruments	23,900	32,497
Total Current Assets	229,478	347,980
Property and Equipment
Oil and natural gas properties - full cost method of accounting, including $539.4 million and $418.8 million of unevaluated properties not being amortized at March 31, 2013 and June 30, 2012, respectively	3,148,239	2,698,213
Other property and equipment	16,114	9,533
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	3,164,353	2,707,746
Other Assets
Derivative financial instruments	17,134	45,496
Debt issuance costs, net of accumulated amortization	29,599	27,608
Equity method investments	13,408	2,117
Total Other Assets	60,141	75,221
Total Assets	3,453,972	3,130,947
Current Liabilities
Accounts payable	172,017	156,959
Accrued liabilities	121,564	118,818
Notes payable	1,080	22,211
Asset retirement obligations	30,130	34,457
Derivative financial instruments	112
Current maturities of long-term debt	23,428	4,284
Total Current Liabilities	348,331	336,729
Long-term debt, less current maturities	1,227,144	1,014,060
Deferred income taxes	139,268	104,280
Asset retirement obligations	283,317	266,958
Derivative financial instruments	561
Other liabilities	9,220	3,080
Total Liabilities	2,007,841	1,725,107
Commitments and Contingencies (Note 16)
Stockholders' Equity
Preferred stock
Common stock, $0.005 par value, 200,000,000 shares authorized and 79,373,500 and 79,147,340 shares issued and 79,372,837 and 78,837,697 shares outstanding at March 31, 2013 and June 30, 2012, respectively	397	396
Additional paid-in capital	1,510,811	1,501,785
Accumulated deficit	(79,199)	(153,945)
Accumulated other comprehensive income, net of income tax expense	14,121	57,603
Total Stockholders' Equity	1,446,131	1,405,840
Total Liabilities and Stockholders' Equity	3,453,972	3,130,947
7.25% Convertible Perpetual Preferred Stock [Member]
Stockholders' Equity
Preferred stock
5.625% Convertible Perpetual Preferred Stock [Member]
Stockholders' Equity
Preferred stock	$ 1	$ 1

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Long-Term Debt (Interest Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		0 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended	3 Months Ended		9 Months Ended		0 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Revolving Credit Facility [Member]	Mar. 31, 2012 Revolving Credit Facility [Member]	Mar. 31, 2013 Revolving Credit Facility [Member]	Mar. 31, 2012 Revolving Credit Facility [Member]	Mar. 31, 2013 Revolving Credit Facility [Member] Amortization Of Debt Issue Cost	Mar. 31, 2012 Revolving Credit Facility [Member] Amortization Of Debt Issue Cost	Mar. 31, 2013 Revolving Credit Facility [Member] Amortization Of Debt Issue Cost	Mar. 31, 2012 Revolving Credit Facility [Member] Amortization Of Debt Issue Cost	Dec. 17, 2010 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2013 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2012 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2013 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2012 9.25 Percent Senior Notes Due 2017 [Member]	Jun. 30, 2012 9.25 Percent Senior Notes Due 2017 [Member]	Mar. 31, 2013 9.25 Percent Senior Notes Due 2017 [Member] Amortization Of Debt Issue Cost	Mar. 31, 2012 9.25 Percent Senior Notes Due 2017 [Member] Amortization Of Debt Issue Cost	Mar. 31, 2013 9.25 Percent Senior Notes Due 2017 [Member] Amortization Of Debt Issue Cost	Mar. 31, 2012 9.25 Percent Senior Notes Due 2017 [Member] Amortization Of Debt Issue Cost	Feb. 25, 2011 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2013 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2012 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2013 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2012 7.75 Percent Senior Notes Due 2019 [Member]	Mar. 31, 2013 7.75 Percent Senior Notes Due 2019 [Member] Amortization Of Debt Issue Cost	Mar. 31, 2012 7.75 Percent Senior Notes Due 2019 [Member] Amortization Of Debt Issue Cost	Mar. 31, 2013 7.75 Percent Senior Notes Due 2019 [Member] Amortization Of Debt Issue Cost	Mar. 31, 2012 7.75 Percent Senior Notes Due 2019 [Member] Amortization Of Debt Issue Cost	Mar. 31, 2013 Derivative Instruments Premium Financing [Member]	Mar. 31, 2012 Derivative Instruments Premium Financing [Member]	Mar. 31, 2013 Derivative Instruments Premium Financing [Member]	Mar. 31, 2012 Derivative Instruments Premium Financing [Member]
Debt Instrument [Line Items]
Interest expense	$ 27,682	$ 26,887	$ 81,339	$ 82,438	$ 3,330	$ 2,201	$ 8,185	$ 7,291	$ 1,261	$ 1,238	$ 3,762	$ 3,645		$ 17,343	$ 17,344	$ 52,031	$ 52,031		$ 552	$ 552	$ 1,655	$ 1,655		$ 4,843	$ 4,843	$ 14,531	$ 14,531	$ 97	$ 97	$ 291	$ 291	$ 256	$ 612	$ 884	$ 2,994
Debt instrument, stated interest rate													9.25%	9.25%		9.25%		9.25%					7.75%	7.75%		7.75%
Debt Maturity Date													Dec. 15, 2017			Dec. 15, 2017		Dec. 15, 2017					Jun. 15, 2019

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Cash Flows From Operating Activities
Net income	$ 40,436	$ 91,252	$ 100,028	$ 254,672
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	88,727	88,448	279,378	260,819
Deferred income tax expense	25,625	8,764	58,439	30,036
Change in derivative financial instruments
Proceeds from derivative instruments	574	993	735	66,522
Other - net	(5,318)	(10,866)	(19,336)	(36,557)
Accretion of asset retirement obligations	7,649	9,762	23,057	29,253
Loss from equity method investees	2,587		4,698
Amortization and write-off of debt issuance costs	1,910	1,886	5,708	5,591
Stock-based compensation	483	478	2,139	10,592
Changes in operating assets and liabilities
Accounts receivable	(1,858)	(9,565)	(9,254)	(27,146)
Prepaid expenses and other current assets	19,541	9,945	40,263	4,879
Settlement of asset retirement obligations	(4,761)	(4,569)	(29,570)	(6,563)
Accounts payable and accrued liabilities	34,314	11,670	(4,740)	(25,916)
Net Cash Provided by Operating Activities	209,909	198,198	451,545	566,182
Cash Flows from Investing Activities
Acquisitions	(112,566)	(35)	(153,722)	(6,212)
Capital expenditures	(184,504)	(155,744)	(563,554)	(394,188)
Insurance payments received				6,472
Net contributions to equity investees	(503)		(16,027)
Proceeds from the sale of properties		203		2,970
Other	(409)	1,252	(54)	444
Net Cash Used in Investing Activities	(297,982)	(154,324)	(733,357)	(390,514)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	499	191	5,259	9,647
Conversion of preferred stock to common		(6,029)		(6,029)
Dividends to shareholders - common	(5,556)		(16,659)
Dividends to shareholders - preferred	(2,873)	(2,877)	(8,623)	(10,289)
Proceeds from long-term debt	532,990	185,437	1,142,439	707,761
Payments on long-term debt	(447,653)	(214,468)	(928,914)	(818,787)
Other			1,452	(854)
Net Cash Provided by (Used in) Financing Activities	77,407	(37,746)	194,954	(118,551)
Net Increase (decrease) in Cash and Cash Equivalents	(10,666)	6,128	(86,858)	57,117
Cash and Cash Equivalents, beginning of period	40,895	79,396	117,087	28,407
Cash and Cash Equivalents, end of period	$ 30,229	$ 85,524	$ 30,229	$ 85,524

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Employee Benefit Plans (Compensation Expense Recognized And Shares Issued Under Employee Stock Purchase Plan) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Employee Benefit Plans [Abstract]
Compensation expense	$ 221	$ 215	$ 598	$ 516
Shares issued			27,608	21,015

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Commitments And Contingencies (Tables)

9 Months Ended

Mar. 31, 2013

Commitments And Contingencies [Abstract]

Future Minimum Lease Commitments Under Operating Leases

Twelve Months Ended March 31,
2014	$ 2,821
2015	2,980
2016	2,776
2017	2,849
2018	2,559
Thereafter	1,936
Total	$ 15,921

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Commitments And Contingencies (Future Minimum Lease Commitments Under Operating Lease) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013
Commitments And Contingencies [Abstract]
2014	$ 2,821
2015	2,980
2016	2,776
2017	2,849
2018	2,559
Thereafter	1,936
Total	$ 15,921

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Commitments And Contingencies

9 Months Ended

Mar. 31, 2013

Commitments And Contingencies [Abstract]

Commitments And Contingencies

Note 16 — 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 effect on our consolidated financial position, results of operations or cash flows.

Lease Commitments.   We have a non-cancelable operating lease for office space and other that expires on March 31, 2018. Future minimum lease commitments as of March 31, 2013 under the operating lease are as follows (in thousands):

Twelve Months Ended March 31,
2014	$ 2,821
2015	2,980
2016	2,776
2017	2,849
2018	2,559
Thereafter	1,936
Total	$ 15,921

Rent expense, including rent incurred on short-term leases, for the three months ended March 31, 2013 and 2012 was $861,000 and $942,000, respectively, and for the nine months ended March 31, 2013 and 2012 was $2,122,000 and $1,839,000, respectively.

Letters of Credit and Performance Bonds.   We had $225.3 million in letters of credit and $44.4 million of performance bonds outstanding as of March 31, 2013.

Line of Credit.   Our equity method investee, EXXI M21K, of which we own 20%, is a guarantor of a $100 million line of credit entered into by M21K on February 23, 2012. See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

Guarantee. We are a guarantor of a $100 million line of credit entered into by M21K.  See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report. We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K estimated at $65 million and $1.8 million, respectively.  For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years.  See Note 14 – Related Party Transactions of Notes to Consolidated Financial Statements in this Quarterly Report.

Drilling Rig Commitments.   As of March 31, 2013, we have entered into seven drilling rig commitments:

1)  January 16, 2013 to June 30, 2013 at $49,000 per day

2)  January 1, 2013 to September 30, 2013 at $110,000 per day

3)  January 1, 2013 to September 30, 2013 at $110,000 per day

4)  March 5, 2013 to September 5, 2013 at $130,000 per day

5)  October 2, 2012 to June 1, 2013 at $90,000 per day

6)  February 15, 2013 to July 15, 2013 at $39,000 per day

7)  March 15, 2013 to July 1, 2013 at $36,000 per day

At March 31, 2013, future minimum commitments under these contracts totaled $70.2 million.

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Fair Value Of Financial Instruments (Tables)

9 Months Ended

Mar. 31, 2013

Fair Value Of Financial Instruments [Abstract]

Fair Value Of Financial Instruments

	Level 1					Level 2
	March 31,			June 30,		March 31,		June 30,
	2013		2012			2013		2012
Assets:
Oil and natural gas derivatives						$	85,467	$	170,955
Liabilities:
Oil and natural gas derivatives						$	45,106	$	92,962
Restricted stock units	$	6,964	$		15,124
Time-based performance units		2,397			4,434
Total liabilities	$	9,361	$		19,558	$	45,106	$	92,962

The following table describes the changes to our Level 3 financial instruments (in thousands):

	Level 3
	Nine Months Ended      March 31,
	2013		2012
Liabilities:
Performance-based performance units
Balance at beginning of period	$	22,855	$	20,305
Vested		(23,161)		(23,807)
Grants and changes in fair value charged to general and administrative expense		10,264		23,320
Balance at end of period	$	9,958	$	19,818

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Prepayments And Accrued Liabilities

9 Months Ended

Mar. 31, 2013

Prepayments And Accrued Liabilities [Abstract]

Prepayments And Accrued Liabilities

Note 18 — Prepayments and Accrued Liabilities

Prepayments and accrued liabilities consist of the following (in thousands):

	March 31,	June 30,
	2013	2012
Prepaid expenses and other current assets
Advances to joint interest partners	$ 3,059	$ 12,966
Insurance	6,801	30,515
Inventory	4,127	4,849
Royalty deposit	1,961	2,443
Short-term stock investment	23	8,786
Other	6,823	3,470
Total prepaid expenses and other current assets	$ 22,794	$ 63,029
Accrued liabilities
Advances from joint interest partners	$ 10,264	$ 301
Employee benefits and payroll	29,132	53,541
Interest	28,037	3,721
Accrued hedge payable	4,228	136
Undistributed oil and gas proceeds	46,757	54,484
Other	3,146	6,635
Total accrued liabilities	$ 121,564	$ 118,818

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Prepayments And Accrued Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2012
Prepaid expenses and other current assets
Advances to joint interest partners	$ 3,059	$ 12,966
Insurance	6,801	30,515
Inventory	4,127	4,849
Royalty deposit	1,961	2,443
Short-term stock investment	23	8,786
Other	6,823	3,470
Total prepaid expenses and other current assets	22,794	63,029
Accrued liabilities
Advances from joint interest partners	10,264	301
Employee benefits and payroll	29,132	53,541
Interest	28,037	3,721
Accrued hedge payable	4,228	136
Undistributed oil and gas proceeds	46,757	54,484
Other	3,146	6,635
Total accrued liabilities	$ 121,564	$ 118,818

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Basis Of Presentation

9 Months Ended

Mar. 31, 2013

Basis Of Presentation [Abstract]

Basis Of Presentation

ENERGY XXI (BERMUDA) LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 1 — Basis of Presentation

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

    References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries.  We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

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

    Interim Financial Statements.   The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended June 30, 2012 (the “2012 Annual Report”).

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

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	9 Months Ended	12 Months Ended
	Mar. 31, 2013	Jun. 30, 2012
Oil and natural gas properties - full cost method of accounting, unevaluated properties	539,354	418,760
Preferred stock, par value	0.001	0.001
Preferred stock, shares authorized	7,500,000	7,500,000
Common stock, par value	0.005	0.005
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	79,373,500	79,147,340
Common stock, shares outstanding	79,372,837	78,837,697
7.25% Convertible Perpetual Preferred Stock [Member]
Preferred stock, shares issued	8,000	8,000
Preferred stock, shares outstanding	8,000	8,000
Preferred stock dividend rate	7.25%	7.25%
5.625% Convertible Perpetual Preferred Stock [Member]
Preferred stock, shares issued	813,188	814,117
Preferred stock, shares outstanding	813,188	814,117
Preferred stock dividend rate	5.625%	5.625%

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Stockholders' Equity

9 Months Ended

Mar. 31, 2013

Stockholders' Equity [Abstract]

Stockholders' Equity

Note 11 – Stockholders’ Equity

Common Stock

On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on The NASDAQ Global Select Market (“NASDAQ”). Our common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders.

We paid quarterly cash dividends of $0.07 per share to holders of the Company’s common stock for the quarters ended June 30, 2012, September 30, 2012 and December 31, 2012 on September 14, 2012,  December 14, 2012 and March 15, 2013 respectively.

On May 1, 2013, our board of directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of the Company’s common stock. The quarterly dividend will be paid on June 14, 2013 to shareholders of record on May 31, 2013.

Preferred Stock

Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock.  Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock.  Shares of previously issued preferred stock that have been cancelled are available for future issuance.

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

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

Conversion of Preferred Stock

During the nine months ended March 31, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.

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Document and Entity Information	9 Months Ended
	Mar. 31, 2013	Apr. 26, 2013
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Trading Symbol	exxi
Entity Registrant Name	ENERGY XXI (BERMUDA) LTD
Entity Central Index Key	0001343719
Current Fiscal Year End Date	--06-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		79,374,772

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Supplemental Cash Flow Information

9 Months Ended

Mar. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Note 12 – Supplemental Cash Flow Information

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

	Three Months Ended      March 31,		Nine Months Ended      March 31,
	2013	2012	2013	2012
Cash paid for interest	$ 3,402	$ 4,698	$ 50,591	$ 56,721
Cash paid for income taxes	4,056	—	7,017	—

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

	Three Months Ended March 31,		Nine Months Ended      March 31,
	2013	2012	2013	2012
Financing of insurance premiums	$ (1,266)	$ (8,558)	$ (21,131)	$ (19,215)
Derivative instruments premium financing	12,780	15,557	14,001	12,869
Preferred stock dividends	(53)	(138)	(593)	(138)
Additions to property and equipment by recognizing asset retirement obligations	1,816	700	11,605	2,037

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Consolidated Statements Of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Revenues
Oil sales	$ 274,364	$ 312,714	$ 807,518	$ 868,978
Natural gas sales	29,410	23,282	87,002	92,479
Total Revenues	303,774	335,996	894,520	961,457
Costs and Expenses
Lease operating	86,305	78,447	254,708	223,614
Production taxes	1,352	1,499	3,765	4,847
Gathering and transportation	4,411	2,465	18,500	12,013
Depreciation, depletion and amortization	88,727	88,448	279,378	260,819
Accretion of asset retirement obligations	7,649	9,762	23,057	29,253
General and administrative expense	16,092	25,075	59,299	66,543
(Gain) loss on derivative financial instruments	(632)	3,495	5,755	(2,506)
Total Costs and Expenses	203,904	209,191	644,462	594,583
Operating Income	99,870	126,805	250,058	366,874
Other Income (Expense)
Loss from equity method investees	(2,587)		(4,698)
Other income - net	523	97	1,425	121
Interest expense	(27,682)	(26,887)	(81,339)	(82,438)
Total Other Expense	(29,746)	(26,790)	(84,612)	(82,317)
Income Before Income Taxes	70,124	100,015	165,446	284,557
Income Tax Expense	29,688	8,763	65,418	29,885
Net Income	40,436	91,252	100,028	254,672
Induced Conversion of Preferred Stock		6,058		6,058
Preferred Stock Dividends	2,873	2,739	8,623	10,151
Net income available for common stockholders	$ 37,563	$ 82,455	$ 91,405	$ 238,463
Earnings Per Share
Basic	$ 0.47	$ 1.06	$ 1.15	$ 3.10
Diluted	$ 0.46	$ 1.04	$ 1.14	$ 2.92
Weighted Average Number of Common Shares Outstanding
Basic	79,365	77,454	79,280	76,803
Diluted	87,516	87,353	87,471	87,185

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Long-Term Debt

9 Months Ended

Mar. 31, 2013

Long-Term Debt [Abstract]

Long-Term Debt

Note 6 – Long-Term Debt

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

	March 31,	June 30,
	2013	2012
Revolving credit facility	$ 212,831	$—
9.25% Senior Notes due 2017	750,000	750,000
7.75% Senior Notes due 2019	250,000	250,000
4.14% Promissory Note due 2017	5,289	—
Derivative instruments premium financing	31,387	17,387
Capital lease obligation	1,065	957
Total debt	1,250,572	1,018,344
Less current maturities	23,428	4,284
Total long-term debt	$ 1,227,144	$ 1,014,060

Maturities of long-term debt as of March 31, 2013 are as follows (in thousands):

Twelve Months Ended March 31,
2014	$ 23,428
2015	222,331
2016	813
2017	465
2018	753,535
Thereafter	250,000
Total	$ 1,250,572

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by our indirect, wholly-owned subsidiary, Energy XXI Gulf Coast, Inc. (“EGC”), in May 2011. This facility, amended most recently on May 1, 2013, has lender commitments of $1,700 million and matures on April 9, 2018. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions.

On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreementwhich provided EGC the ability to make distributions to us for various purposes,subject to varying limitations depending on the purpose of the distribution.  The ability of EGC to make dividends was subject to EGC meeting minimum liquidity and maximum revolver utilization thresholds, and were further limited to an aggregate cumulative amount equal to $70 million plus 50% of our cumulative Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter. The ability of EGC to make dividend payments to us was modified in subsequent amendments.

On May 24, 2012, EGC entered into the Second Amendment (the “Second Amendment”) to the First Lien Credit Agreement which provided further increased flexibility to make payments from EGC to us and/or our other subsidiaries. The Second Amendment includes the following: (a) removal of limitations on the ability of EGC to finance hedge option premiums; (b) technical modifications in regard to the ability of EGC to reposition hedges; (c) adjustment of definitions and other provisions to further increase the ability of EGC to make distributions to us and/or our subsidiaries; and (d) technical corrections in connection with the replacement of one of the lenders (including that lender’s role as an issuer of a letter of credit) under the First Lien Credit Agreement.

On October 19, 2012, EGC entered into the Third Amendment (the “Third Amendment”) to the First Lien Credit Agreement. The Third Amendment provides changes, supplements, and other modifications for information specific to the lenders under the First Lien Credit Agreement and increases the borrowing base to $825 million.

On April 9, 2013, EGC entered into the Fourth Amendment (the “Fourth Amendment”) to the First Lien Credit Agreement. The Fourth Amendment includes the following: (a) extension of the maturity date to April 9, 2018 (b) increase of commitments under the First Lien Credit Agreement from $925 million to $1,700 million, (c) increase in the borrowing base to $850 million, (d) reduction of the ranges of applicable margins on all borrowing by 0.25% to 0.50%, (e) approval of an increase in the cash distribution basket under which EGC can make dividend payments on its preferred and common stock, from $17 million to $50 million per calendar year, (f) increase in the general basket of permitted unsecured indebtedness from $250 million to $750 million, subject to a reduction in the borrowing base of 25 percent of any unsecured indebtedness issued in excess of $250 million, and (g) approval of additional ability of an affiliated entity to reinsure the assets and operations of EGC and its subsidiaries.

On May 1, 2013, EGC entered into the Fifth Amendment (the “Fifth Amendment”) to the First Lien Credit Agreement.  The Fifth Amendment provides changes and other modifications to the First Lien Credit Agreement to increase the ability of EGC to make dividends and other distributions to us.  Under the Amendment, EGC now can make such dividends and other distributions in an amount of up to $350 million per calendar year to the extent that, following each distribution, EGC and its subsidiaries have liquidity, in the form of cash and available borrowing capacity under the First Lien Credit Agreement, of the greater of $150 million or 15% of the borrowing base under the First Lien Credit Agreement.  Further, the amendment limits the total aggregate distributions made by EGC to a maximum of $70 million plus 50% of the cumulative consolidated net income of EGC between October 1, 2010 and the most recently ended fiscal quarter, and requires that the making of any such dividend or other distributions must otherwise comply with all contractual restrictions and obligations applicable to EGC.

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

As of March 31, 2013, we were in compliance with all covenants under our First Lien Credit Agreement.

High Yield Facilities

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million aggregate principal amount of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Senior Notes”). On July 8, 2011, we exchanged $749 million aggregate principal amount of the 9.25% Notes for $749 million aggregate principal amount of newly issued notes registered under the Securities Act of 1933, as amended (the “Securities Act”) which bear identical terms and conditions as the 9.25% Senior Notes. The trading restrictions on the remaining $1 million principal amount of the 9.25% Senior Notes were lifted on December 17, 2011.

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 9.25% Senior Notes under various circumstances and are required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which is defined in the indenture governing the 9.25% Senior Notes.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of March 31, 2013 was $848.9 million based on quoted prices.There is no active market for the 9.25% Senior Notes; therefore, the fair value is classified within Level 2.

The 9.25%  Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

7.75% Senior Notes

On February 25, 2011, EGC issued $250 million aggregate principal amount of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Senior Notes”). On July 7, 2011, we exchanged the full $250 million aggregate principal amount of the 7.75% Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act which bear identical terms and conditions as the 7.75% Senior Notes.

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

We have the right to redeem the 7.75% Senior Notes under various circumstances and are required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which is defined in the indenture governing the 7.75% Senior Notes.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of March 31, 2013 was $271.3 million based on quoted prices. There is no active marketfor the 7.75% Senior Notes; therefore, the fair value is classified within Level 2.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

Promissory Note

In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment.  Under this note we are required to make a monthly payment of approximately $52,000 and one lump-sum payment of $3.3 million at maturity, in October 2017.  This note carries an interest of 4.14% per annum.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of March 31, 2013 and June 30, 2012, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $31.4 million and $17.4 million, respectively.

Interest Expense

For the three months and nine months ended March 31, 2013 and 2012, interest expense consisted of the following (in thousands):

	Three Months Ended March 31,		Nine Months Ended March 31,
	2013	2012	2013	2012
Revolving credit facility	$ 3,330	$ 2,201	$ 8,185	$ 7,291
9.25% Senior Notes due 2017	17,343	17,344	52,031	52,031
7.75% Senior Notes due 2019	4,843	4,843	14,531	14,531
Amortization of debt issue cost - Revolving credit facility	1,261	1,238	3,762	3,645
Amortization of debt issue cost – 9.25% Senior Notes due 2017	552	552	1,655	1,655
Amortization of debt issue cost – 7.75% Senior Notes due 2019	97	97	291	291
Derivative instruments financing and other	256	612	884	2,994
	$ 27,682	$ 26,887	$ 81,339	$ 82,438

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Equity Method Investments

9 Months Ended

Mar. 31, 2013

Equity Method Investments [Abstract]

Equity Method Investments

Note 5 - Equity Method Investments

20%  interest in Energy XXI M21K, LLC (“EXXI M21K”)

We own a 20% interest in EXXI M21K. EXXI M21K engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).

On June 4, 2012, M21K entered into a Purchase and Sale Agreement (“PSA Agreement”) with EP Energy E&P Company, L.P. (“EP Energy”) to acquire interests in certain oil and gas fields owned by EP Energy. The total purchase price, subject to adjustments in accordance with the terms of the PSA Agreement was $103 million. The effective date of the acquisition is January 1, 2012.

   On July 19, 2012, M21K closed on the acquisition and we paid our share of the remaining purchase price of $16 million to EP Energy, prior to final adjustments. EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K (“M21K First Lien Credit Agreement”). Simultaneous with the closing of the acquisition of assets from EP Energy, M21K entered into the First Amendment to the M21K First Lien Credit Agreement, which made technical changes to defined terms and hedging requirements, as well as establishing the borrowing base under the facility at $25 million.

On December 12, 2012, in conjunction with the name change from Natural Gas Partners Assets, LLC to M21K, LLC, M21K entered into the Second Amendment to the M21K First Lien Credit Agreement to reflect the name change and make technical changes to borrowing procedures.  

   On April 9, 2013, M21K entered into the Third Amendment to the M21K First Lien Credit Agreement that made technical modification of a defined term and reduced the borrowing base to $24 million with further reduction to $20 million within ninety days from the amendment date. 

   We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K.  See Note 14 – Related Party Transactions of Notes to Consolidated Financial Statements in this Quarterly Report.

    As of March 31, 2013, our investment in EXXI M21K was approximately $12.7 million, and we had incurred $1.7 million and $2.0 million in equity losses for the three months and nine months ended March 31, 2013, respectively.

49% interest in Ping Energy XXI Limited (“Ping Energy”)

   Our wholly-owned subsidiary Energy XXI International Limited (“EXXI International”) owns a 49% interest in Ping Energy, which is active in the pursuit to identify and acquire exploratory, developmental and producing oil and gas properties in South East Asia. 

   As of March 31, 2013, our investment in Ping Energy was approximately $0.7 million and we had incurred $0.9 million and $2.7 million in equity losses for the three months and nine months ended March 31, 2013, respectively.

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Fair Value Of Financial Instruments

9 Months Ended

Mar. 31, 2013

Fair Value Of Financial Instruments [Abstract]

Fair Value Of Financial Instruments

Note 17 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 – Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

• Level 1 — quoted prices in active markets for identical assets or liabilities.

• Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

• Level 3 — unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):

	Level 1					Level 2
	March 31,			June 30,		March 31,		June 30,
	2013		2012			2013		2012
Assets:
Oil and natural gas derivatives						$	85,467	$	170,955
Liabilities:
Oil and natural gas derivatives						$	45,106	$	92,962
Restricted stock units	$	6,964	$		15,124
Time-based performance units		2,397			4,434
Total liabilities	$	9,361	$		19,558	$	45,106	$	92,962

The following table describes the changes to our Level 3 financial instruments (in thousands):

	Level 3
	Nine Months Ended      March 31,
	2013		2012
Liabilities:
Performance-based performance units
Balance at beginning of period	$	22,855	$	20,305
Vested		(23,161)		(23,807)
Grants and changes in fair value charged to general and administrative expense		10,264		23,320
Balance at end of period	$	9,958	$	19,818

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Employee Benefit Plans

9 Months Ended

Mar. 31, 2013

Employee Benefit Plans [Abstract]

Employee Benefit Plans

Note 13 – 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 (“Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Restricted 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 Restricted Stock Units.

Performance Units

For fiscal 2010, 2011 and 2012, we also awarded performance units (“Performance Units”). Of the total Performance Units awarded, 25% are time-based Performance Units (“Time-Based Performance Units”) and 75% are total shareholder return performance-based units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.

At our discretion, at the time the Restricted Stock Units and Performance Units vest, employees will settle in either common shares or cash. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable. Historically, we have paid all Restricted Stock Units vesting awards in cash. Performance Unit awards were paid 50% in common stock and future vesting of the Performance Units may be paid in common stock at the discretion of our board of directors.  

We recognized compensation expense related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Restricted Stock Units	$	1,941	$	6,897	$	9,668	$	17,032
Performance Units		231		10,055		13,086		27,007
Total compensation expense recognized	$	2,172	$	16,952	$	22,754	$	44,039

As of March 31, 2013, we have886,626 unvested Restricted Stock Units and5,170,042 unvested Performance Units.

Stock Purchase Plan

Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or that have been newly issued by us. During the nine months ended March 31, 2013 and 2012, we issued208,988 shares and 277,980 shares, respectively, under the 2008 Purchase Plan.

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from January 1, 2013 to June 30, 2013. We use Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive.  The compensation expense recognized and shares issued under Employee Stock Purchase Plan were as follows (in thousands, except for shares):

	Three Months Ended   March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Compensation expense	$	221	$	215	$	598	$	516
Shares issued		—		—		27,608		21,015

Stock Options

In September 2008, our board of directors granted 300,000 stock options to certain officers. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. As of March 31, 2013,  100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.

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

	2013			2012
	Shares Under Option		Weighted Ave. Exercise Price	Shares Under Option			Weighted Ave. Exercise Price
Beginning balance		—			100,000		$	17.50
Vested		—			(100,000	)		17.50
Ending balance		—			—

Our net income for the three and nine months ended March 31, 2013 and 2012 includes approximately $0, $0, $0 and $58,000, respectively of compensation costs related to stock options.

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

Defined Contribution Plans

Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401(k) Plan that provides for matching. The contributions under these plans were as follows (in thousands):

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Profit Sharing Plan	$	(481)	$	(49)	$	1,712	$	1,756
401(k) Plan		1,587		1,360		2,948		2,866
Total contributions	$	1,106	$	1,311	$	4,660	$	4,622

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Derivative Financial Instruments

9 Months Ended

Mar. 31, 2013

Derivative Financial Instruments [Abstract]

Derivative Financial Instruments

Note 9 – Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions for our derivative transactions to reduce the concentration of exposure to any individual counterparty and 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. We designate a majority of our derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

When we discontinue cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

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 consisting of 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, ICE) plus the difference between the purchased put and the sold put strike price.

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. Historically the basis differential between HLS and WTI has been relatively small and predictable. Over the past five years, HLS has averaged approximately $1 per barrel premium to WTI. Since the beginning of 2011, the HLS/WTI basis differential and volatility has increased with HLS carrying as much as a $30 per barrel premium to WTI. During the quarter ended September 30, 2011, we began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and price risk.

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 helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended March 31, 2013, and received $181.1 million.  These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts.  As of March 31, 2013, we had $13.5 million of monetized amounts remaining in OCI of which $4.5 million will be recognized during each of the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

During the quarter ended March 31, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and will be recognized in income over the life of the underlying hedge contracts through December 31, 2013.  As of March 31, 2013, we had $2.0 million in deferred hedge revenue of which $0.6 million, $0.7 million, and $0.7 million will be recognized during the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013, respectively.

As of March 31, 2013, we had the following net open crude oil derivative positions:

					Weighted Average Contract Price
					Swaps	Collars/Put Spread
Period	Type of Contract	Index	Volumes (MBbls)		Fixed Price	Sub Floor	Floor	Ceiling
April 2013 - December 2013	Three-Way Collars	Oil-Brent-IPE	2,570	(1)		$ 85.72	$ 105.72	$ 126.72
April 2013 - December 2013	Put Spreads	Oil-Brent-IPE	1,830			87.00	106.25
April 2013 - December 2013	Three-Way Collars	NYMEX-WTI	1,375			70.00	90.00	136.32
April 2013 - December 2013	Collars	NYMEX-WTI	963				73.57	105.63
April 2013 - December 2013	Swaps	NYMEX-WTI	138		$ 86.60
April 2013 - December 2013	Swaps	NYMEX-WTI	(138)		88.20
January 2014 - December 2014	Three-Way Collars	Oil-Brent-IPE	2,373			68.08	88.08	130.88
January 2014 - December 2014	Collars	Oil-Brent-IPE	730				90.00	108.38
January 2014 - December 2014	Three-Way Collars	NYMEX-WTI	3,650			70.00	90.00	137.14
January 2015 - December 2015	Three-Way Collars	Oil-Brent-IPE	1,825			72.00	92.00	111.56

(1) The Oil-Brent-IPE three-way collars for the period from April 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

As of March 31, 2013, we had the following open natural gas derivative positions:

				Weighted Average Contract Price
				Collars/Call Spread
Period	Type of Contract	Index	Volumes (MMBtu)	Sub Floor	Floor	Ceiling
April 2013 - December 2013	Three-Way Collars	NYMEX-HH	8,250	$ 4.07	$ 4.93	$ 5.87
January 2014 – December 2014	Call Spread	NYMEX-HH	913	4.20	5.00

The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):

	Asset Derivative Instruments								Liability Derivative Instruments
	March 31, 2013				June 30, 2012				March 31, 2013				June 30, 2012
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments		Current	$	37,233		Current	$	66,716		Current	$	13,622		Current	$	34,462
		Non-Current		43,294		Non-Current		103,462		Non-Current		26,896		Non-Current		58,229
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		4,621		Current		326		Current		4,444		Current		83
		Non-Current		319		Non-Current		451		Non-Current		144		Non-Current		188
Total			$	85,467			$	170,955			$	45,106			$	92,962

The effect of derivative instruments on our consolidated statements of income was as follows (in thousands):

	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Location of (Gain)Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(1,084)	$	3,009	$	(10,455)	$	2,576
Natural gas sales		(2,340)		(4,128)		(12,879)		(23,528)
Total cash settlements		(3,424)		(1,119)		(23,334)		(20,952)
Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instrumentsIneffective portion of commodity derivative instruments		(816)		3,388		3,800		1,713
Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		(41)		23		1,832		(5,001)
Unrealized mark to market (gain) loss		225		84		123		782
Total (gain) loss on derivative financial instruments		(632)		3,495		5,755		(2,506)
Total gain	$	(4,056)	$	2,376	$	(17,579)	$	(23,458)

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

Location of (Gain)/Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Three Months Ended March 31, 2013
Commodity Derivative Instruments	$	5,964
Revenues			$	(4,657)
(Gain) loss on derivative financial instruments					$	(816)
Total	$	5,964	$	(4,657)	$	(816)
Three Months Ended March 31, 2012
Commodity Derivative Instruments	$	39,757
Revenues			$	(1,349)
(Gain) loss on derivative financial instruments					$	3,388
Total	$	39,757	$	(1,349)	$	3,388
Nine Months Ended March 31, 2013
Commodity Derivative Instruments	$	43,482
Revenues			$	(18,526)
(Gain) loss on derivative financial instruments					$	3,800
Total	$	43,482	$	(18,526)	$	3,800
Nine Months Ended March 31, 2012
Commodity Derivative Instruments	$	(52,837)
Revenues			$	(16,658)
(Gain) loss on derivative financial instruments					$	1,713
Total	$	(52,837)	$	(16,658)	$	1,713

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $15.9 million ($10.3 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position from counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At March 31, 2013, we had no deposits for collateral with our counterparties.

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Employee Benefit Plans (Summary Of Stock Option Activity And Related Information) (Details) (USD $)	Mar. 31, 2013	Mar. 31, 2012	Jun. 30, 2011
Unvested Shares Under Option
Beginning balance			100,000
Vested		(100,000)
Ending balance			100,000
Weighted Ave. Exercise Price
Beginning balance			$ 17.50
Vested		$ 17.50
Ending balance			$ 17.50

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Notes Payable

9 Months Ended

Mar. 31, 2013

Notes Payable [Abstract]

Notes Payable

Note 7 – Notes Payable

In May 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $26.0 million and bore interest at an annual rate of 1.556%. The note matured and was repaid on December 26, 2012.

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note is for a total face amount of $3.6 million and bears interest at an annual rate of 1.667%. The note amortizes over the remaining term of the insurance, which matures May 1, 2013.  The balance outstanding as of March 31, 2013 was $0.7 million.

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums.  The note was for a total face amount of $0.6 million and bears interest at an annual rate of 1.774%.  The note amortizes over the remaining term of the insurance, which matures October 23, 2013.  The balance outstanding as of March 31, 2013 was $0.3 million.

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Asset Retirement Obligations

9 Months Ended

Mar. 31, 2013

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

Note 8 – Asset Retirement Obligations

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

Balance at June 30, 2012	$ 301,415
Liabilities acquired	6,940
Liabilities incurred	11,605
Liabilities settled	(29,570)
Accretion expense	23,057
Total balance at March 31, 2013	313,447
Less current portion	30,130
Long-term balance at March 31, 2013	$ 283,317

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Income Taxes

9 Months Ended

Mar. 31, 2013

Income Taxes [Abstract]

Income Taxes

Note 10 – Income Taxes

We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods. Currently, our estimated annual effective tax rate is approximately 39.5%. The variance from the U.S. statutory rate of 35% is primarily due to the presence of common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit. Our Bermuda companies continue to report a tax provision reflecting accrued 30% U.S. withholding tax required on anyinterest (and interest equivalent) payments made from the U.S. companies to the Bermuda companies. We have accrued an additional withholding obligation of $10.4 million for the nine months ended March 31, 2013.  

              In this quarter, we adjusted our valuation allowance to reflect the annual reconciliation of our US income tax return just filed to our previous estimates. We have a remaining valuation allowance of $30.0 million (related to certain State of Louisiana tax attributes and other property matters). In this quarter, we made a cash withholding tax payment of $3.9 million on outbound accrued intercompany interest paid to Bermuda.  This withholding tax was previously accrued and did not result in additional income tax expense being recognized.  Similar cash withholding tax payments would be made in the future when additional intercompany interest is paid. While we have not made a cash income tax payment in this quarter, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (AMT) in subsequent quarters  may be required (possibly as early as the fourth quarter of fiscal year 2013). At this time, we do not believe the federal estimated income tax payments for this fiscal year will exceed $5 million.  We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

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Commitments And Contingencies (Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended	9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012 item	Mar. 31, 2013	Mar. 31, 2012	Jun. 30, 2012	Feb. 23, 2012
Loss Contingencies [Line Items]
Rent expense	$ 861,000	$ 942,000		$ 2,122,000	$ 1,839,000
Letters of credit	225,300,000			225,300,000
Performance bonds outstanding	44,400,000			44,400,000
Amount of line of credit							100,000,000
Asset retirement obligation	313,447,000			313,447,000		301,415,000
Number of drilling rig commitments			7
Estimated drilling rig commitment	70,200,000			70,200,000
Energy XXI M21K LLC [Member]
Loss Contingencies [Line Items]
Equity method investment ownership percentage	20.00%			20.00%			20.00%
Asset retirement obligation	65,000,000			65,000,000
Other Liabilities	1,800,000			1,800,000
Due from related party	6,300,000			6,300,000
Due from related party, commitment period	3 years			3 years
January 16, 2013 To June 30, 2013 [Member]
Loss Contingencies [Line Items]
Drilling rig commitments amount per day	49,000			49,000
January 1, 2013 To September 30, 2013 [Member]
Loss Contingencies [Line Items]
Drilling rig commitments amount per day	110,000			110,000
March 5, 2013 To September 5, 2013 [Member]
Loss Contingencies [Line Items]
Drilling rig commitments amount per day	130,000			130,000
October 2, 2012 To June 1, 2013 [Member]
Loss Contingencies [Line Items]
Drilling rig commitments amount per day	90,000			90,000
February 15, 2013 To July 15, 2013 [Member]
Loss Contingencies [Line Items]
Drilling rig commitments amount per day	39,000			39,000
March 15, 2013 To July 1, 2013 [Member]
Loss Contingencies [Line Items]
Drilling rig commitments amount per day	$ 36,000			$ 36,000

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Fair Value Of Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2012
Fair Value, Inputs, Level 1 [Member]
Liabilities:
Fair value of liabilities	$ 9,361	$ 19,558
Fair Value, Inputs, Level 1 [Member] | Restricted Stock Units (RSUs) [Member]
Liabilities:
Fair value of liabilities	6,964	15,124
Fair Value, Inputs, Level 1 [Member] | Performance Units [Member]
Liabilities:
Fair value of liabilities	2,397	4,434
Fair Value, Inputs, Level 2 [Member]
Liabilities:
Fair value of liabilities	45,106	92,962
Fair Value, Inputs, Level 2 [Member] | Oil and Natural Gas Derivatives [Member]
Assets:
Fair value of assets	85,467	170,955
Liabilities:
Fair value of liabilities	$ 45,106	$ 92,962

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Earnings Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Earnings Per Share [Abstract]
Net income	$ 40,436	$ 91,252	$ 100,028	$ 254,672
Preferred Stock Dividends	2,873	2,739	8,623	10,151
Induced Conversion of Preferred Stock		6,058		6,058
Net income available for common stockholders	$ 37,563	$ 82,455	$ 91,405	$ 238,463
Weighted average shares outstanding for basic EPS	79,365	77,454	79,280	76,803
Add dilutive securities	8,151	9,899	8,191	10,382
Weighted average shares outstanding for diluted EPS	87,516	87,353	87,471	87,185
Basic	$ 0.47	$ 1.06	$ 1.15	$ 3.10
Diluted	$ 0.46	$ 1.04	$ 1.14	$ 2.92

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Earnings per Share (Tables)

9 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Calculation Of Basic And Diluted Earnings Per Share

	Three Months Ended      March 31,		Nine MonthsEnded      March 31,
	2013	2012	2013	2012
Net income	$ 40,436	$ 91,252	$ 100,028	$ 254,672
Preferred stock dividends	2,873	2,739	8,623	10,151
Induced Conversion of Preferred Stock	—	6,058	—	6,058
Net income available for common stockholders	$ 37,563	$ 82,455	$ 91,405	$ 238,463
Weighted average shares outstanding for basic EPS	79,365	77,454	79,280	76,803
Add dilutive securities	8,151	9,899	8,191	10,382
Weighted average shares outstanding for diluted EPS	87,516	87,353	87,471	87,185
Earnings per share
Basic	$ 0.47	$ 1.06	$ 1.15	$ 3.10
Diluted	$ 0.46	$ 1.04	$ 1.14	$ 2.92

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Derivative Financial Instruments (Schedule Of Derivative Instruments Gain (Loss) In Statement Of Financial Performance) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Total cash settlements	$ (3,424)	$ (1,119)	$ (23,334)	$ (20,952)
Realized mark to market (gain) loss	(574)	(993)	(735)	(66,522)
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments	(816)	3,388	3,800	1,713
Total (gain) loss	(4,056)	2,376	(17,579)	(23,458)
Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total cash settlements	(1,084)	3,009	(10,455)	2,576
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total cash settlements	(2,340)	(4,128)	(12,879)	(23,528)
Commodity Contracts [Member] | Designated As Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments	(816)	3,388	3,800	1,713
Commodity Contracts [Member] | Not Designated As Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized mark to market (gain) loss	(41)	23	1,832	(5,001)
Unrealized mark to market (gain) loss	225	84	123	782
(Gain) loss on derivative instruments	$ (632)	$ 3,495	$ 5,755	$ (2,506)

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Earnings Per Share

9 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share

Note 15 — 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 convertible preferred stock, restricted stock and other common stock equivalents.  The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):

	Three Months Ended      March 31,		Nine MonthsEnded      March 31,
	2013	2012	2013	2012
Net income	$ 40,436	$ 91,252	$ 100,028	$ 254,672
Preferred stock dividends	2,873	2,739	8,623	10,151
Induced Conversion of Preferred Stock	—	6,058	—	6,058
Net income available for common stockholders	$ 37,563	$ 82,455	$ 91,405	$ 238,463
Weighted average shares outstanding for basic EPS	79,365	77,454	79,280	76,803
Add dilutive securities	8,151	9,899	8,191	10,382
Weighted average shares outstanding for diluted EPS	87,516	87,353	87,471	87,185
Earnings per share
Basic	$ 0.47	$ 1.06	$ 1.15	$ 3.10
Diluted	$ 0.46	$ 1.04	$ 1.14	$ 2.92

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Basis of Presentation (Policy)

9 Months Ended

Mar. 31, 2013

Basis Of Presentation [Abstract]

Nature Of Operations

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

    References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI (Bermuda) Limited and its wholly-owned subsidiaries.  We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.

Principles Of Consolidation And Reporting

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

Interim Financial Statements

Interim Financial Statements.   The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended June 30, 2012 (the “2012 Annual Report”).

Use Of Estimates

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

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Derivative Financial Instruments (Schedule Of Derivative Positions) (Details)	Mar. 31, 2013 MMBbls
Oil-Brent-IPE [Member] | April 2013 - December 2013 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	2,570	[1]
Sub Floor	85.72
Floor	105.72
Ceiling	126.72
Oil-Brent-IPE [Member] | April 2013 - December 2013 [Member] | Put Spreads [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	1,830
Sub Floor	87.00
Floor	106.25
Oil-Brent-IPE [Member] | January 2014 - December 2014 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	2,373
Sub Floor	68.08
Floor	88.08
Ceiling	130.88
Oil-Brent-IPE [Member] | January 2014 - December 2014 [Member] | Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	730
Floor	90.00
Ceiling	108.38
Oil-Brent-IPE [Member] | January 2015 - December 2015 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	1,825
Sub Floor	72.00
Floor	92.00
Ceiling	111.56
NYMEX-WTI [Member] | April 2013 - December 2013 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	1,375
Sub Floor	70.00
Floor	90.00
Ceiling	136.32
NYMEX-WTI [Member] | April 2013 - December 2013 [Member] | Swaps [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	138
Fixed Price	86.60
NYMEX-WTI [Member] | April 2013 - December 2013 [Member] | Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	963
Floor	73.57
Ceiling	105.63
NYMEX-WTI [Member] | January 2014 - December 2014 [Member] | Three-Way Collars [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	3,650
Sub Floor	70.00
Floor	90.00
Ceiling	137.14
NYMEX-WTI [Member] | April 2013 - December 2013 2nd [Member] | Swaps [Member] | Crude Oil [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Crude Oil	(138)
Fixed Price	88.20
NYMEX-HH [Member] | April 2013 - December 2013 [Member] | Three-Way Collars [Member] | Natural Gas [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Natural Gas	8,250
Sub Floor	4.07
Floor	4.93
Ceiling	5.87
NYMEX-HH [Member] | January 2014 - December 2014 [Member] | Call Spread [Member] | Natural Gas [Member]
Derivative Instruments And Hedging Activities Disclosure [Line Items]
Volume, Natural Gas	913
Sub Floor	4.20
Floor	5.00

[1] The Oil-Brent-IPE three-way collars for the period from April 2013 through December 2013 include the repositioned derivative contracts referred to above. The newly purchased put spreads have been designated as hedges whereas the call option remaining from the collar after the put was sold no longer qualifies for hedge accounting. However, the combination of the put spread and call contracts effectively result into a three-way collar.

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Equity Method Investments (Narrative) (Details) (USD $)	3 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended	0 Months Ended
	Mar. 31, 2013	Mar. 31, 2013	Jun. 30, 2012	Mar. 31, 2013 Energy XXI M21K LLC [Member]	Mar. 31, 2013 Energy XXI M21K LLC [Member]	Feb. 23, 2012 Energy XXI M21K LLC [Member]	Mar. 31, 2013 Ping Energy XXI Limited	Mar. 31, 2013 Ping Energy XXI Limited	Apr. 09, 2013 Third Amendment [Member] Energy XXI M21K LLC [Member]	Jul. 09, 2013 Third Amendment [Member] Energy XXI M21K LLC [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of investments under the equity method				20.00%	20.00%	20.00%	49.00%	49.00%
Interest in oil and gas fields, purchase price				$ 103,000,000	$ 103,000,000
Share of remaining purchase price				16,000,000	16,000,000
Effective date of acquisition					Jan. 01, 2012
Amount of line of credit				100,000,000	100,000,000
Line of credit current borrowing capacity				25,000,000	25,000,000				24,000,000	20,000,000
Equity (loss) income	(2,587,000)	(4,698,000)		(1,700,000)	(2,000,000)		(900,000)	(2,700,000)
Equity method investment	$ 13,408,000	$ 13,408,000	$ 2,117,000	$ 12,700,000	$ 12,700,000		$ 700,000	$ 700,000
Number of days until futher borrowing capcity is reduced									90 days

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Consolidated Statements Of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Statement of Other Comprehensive Income [Abstract]
Net Income	$ 40,436	$ 91,252	$ 100,028	$ 254,672
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion	(2,010)	(59,089)	(38,393)	106,915
Effective portion reclassified to earnings during the period	(7,165)	(2,075)	(28,502)	(25,627)
Total Other comprehensive income (loss)	(9,175)	(61,164)	(66,895)	81,288
Income Tax (Expense) Benefit	3,211	21,407	23,413	(28,451)
Net Other Comprehensive Income (Loss)	(5,964)	(39,757)	(43,482)	52,837
Comprehensive Income	$ 34,472	$ 51,495	$ 56,546	$ 307,509

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Property And Equipment

9 Months Ended

Mar. 31, 2013

Property And Equipment [Abstract]

Property And Equipment

Note 4 – Property and Equipment

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

	March 31,	June 30,
	2013	2012
Oil and gas properties
Proved properties	$ 4,982,071	$ 4,375,984
Less: Accumulated depreciation, depletion, amortization and impairment	2,373,186	2,096,531
Proved properties	2,608,885	2,279,453
Unproved properties	539,354	418,760
Oil and gas properties	3,148,239	2,698,213
Other property and equipment	31,273	22,132
Less: Accumulated depreciation	15,159	12,599
Other property and equipment	16,114	9,533
Total property and equipment – net of accumulated depreciation, depletion, amortization     and impairment	$ 3,164,353	$ 2,707,746

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Employee Benefit Plans (Compensation Expense Recognized) (Details) (USD $)	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013	Mar. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized	$ 2,172,000	$ 16,952,000	$ 22,754,000	$ 44,039,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized	1,941,000	6,897,000	9,668,000	17,032,000
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized	$ 231,000	$ 10,055,000	$ 13,086,000	$ 27,007,000

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Subsequent Events (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	0 Months Ended		3 Months Ended
	May 01, 2013	May 01, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012
Subsequent Events [Abstract]
Dividends declared date	May 01, 2013
Cash dividend per share	$ 0.12		$ 0.07	$ 0.07	$ 0.07
Dividends payment date	Jun. 14, 2013		Mar. 15, 2013	Dec. 14, 2012	Sep. 14, 2012
Dividends payment record date	May 31, 2013
Stock repurchase program, authorized amount		$ 250

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Acquisitions (Tables)

9 Months Ended

Mar. 31, 2013

Gulf Of Mexico Interests [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation To The Assets Acquired And Liabilities Assumed

Oil and natural gas properties – evaluated	$ 11,088
Oil and natural gas properties – unevaluated	27,721
Asset retirement obligations	(5,353)
Cash paid	$ 33,456

Dynamic Interests [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation To The Assets Acquired And Liabilities Assumed

Oil and natural gas properties – evaluated	$ 1,716
Oil and natural gas properties – unevaluated	6,571
Asset retirement obligations	(1,090)
Cash paid	$ 7,197

McMoran Interest [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation To The Assets Acquired And Liabilities Assumed

Oil and natural gas properties – evaluated	$ 63,186
Oil and natural gas properties – unevaluated	17,184
Net working capital	12
Asset retirement obligations	(382)
Cash paid	$ 80,000

Roda Interest [Member]

Restructuring Cost and Reserve [Line Items]

Purchase Price Allocation To The Assets Acquired And Liabilities Assumed

Oil and natural gas properties – evaluated	$ 33,615
Net working capital	500
Asset retirement obligations	(115)
Cash paid	$ 34,000

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Acquisitions (Narrative) (Details) (USD $)	0 Months Ended
	Oct. 17, 2012 Gulf Of Mexico Interests [Member]	Nov. 07, 2012 Dynamic Interests [Member]	Jan. 17, 2013 McMoran Interest [Member]	Mar. 14, 2013 Roda Interest [Member]	Feb. 01, 2013 Apache Joint Venture [Member]
Restructuring Cost and Reserve [Line Items]
Date of acquisition	Oct. 17, 2012	Nov. 07, 2012	Jan. 17, 2013	Mar. 14, 2013
Business acquisition, cash consideration	$ 33,456,000	$ 7,197,000	$ 80,000,000	$ 34,000,000
Gross acres covered in purchase agreement	5,000
Percentage of equity interest acquired		100.00%		100.00%
Joint venture participation interest					25.00%
Seismic shoot phase term					2 years
Estimated total capital commitment for the joint venture	75,000,000				2,500,000
Estimated capital commitment to acquire seismic data					$ 37,500,000

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Related Party Transactions

9 Months Ended

Mar. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

Note 14 — Related Party Transactions

We have a 20% interest in EXXI M21K and a 49% interest in Ping Energy. We account for these investments using the equity method. See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

We are a guarantor of a $100 million line of credit entered into by M21K.  See Note 5 – Equity Method Investments of Notes to Consolidated Financial Statements in this Quarterly Report.

We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K estimated at $65 million and $1.8 million, respectively.  For this guarantee, M21K has agreed to pay us $6.3 million over a period of three years.  As of March 31, 2013, we have received $1.2 million related to such guarantee.