UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-Q

 

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

For the quarterly period ended December 31, 2011

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 x 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 x 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 x	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 x

As of January 26, 2012, there were 76,523,618 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
PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements		4
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		38
ITEM 4. Controls and Procedures		40
PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings		41
ITEM 1A. Risk Factors		41
ITEM 6. Exhibits		41
SIGNATURES		42
EXHIBIT INDEX		43

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 (this “Quarterly Report”):

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. 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

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) for this call option.

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 installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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 a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension 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)(15) 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.

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.

1

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.

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) for this put option.

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’s subsurface 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 intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

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 undeveloped oil and gas reserves, refer to Rule 4-10(a)(31) of Regulation S-X as promulgated by the SEC.

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

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

Zone is a stratigraphic interval containing one or more reservoirs.

2

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 in order to fund our operations, capital expenditures, and to meet our other obligations;

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

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

• availability, cost and adequacy of insurance coverage;

• competition in the oil and gas industry;

• our inability to retain and attract key personnel;

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

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

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 report and (2) Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2011, as amended (the “2011 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.

3

PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements

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

	December 31, 2011			June 30, 2011
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	79,396		$	28,407
Restricted cash		1,028			—
Accounts receivable
Oil and natural gas sales		141,314			126,194
Joint interest billings		2,814			4,526
Insurance and other		3,661			2,533
Prepaid expenses and other current assets		52,817			47,751
Derivative financial instruments		5,592			22
Total Current Assets		286,622			209,433
Property and Equipment
Oil and natural gas properties – full cost method of accounting, including $516.6 million and $467.3 million of unevaluated properties at December 31, 2011 and June 30, 2011, respectively		2,608,737			2,545,336
Other property and equipment		9,025			8,201
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		2,617,762			2,553,537
Other Assets
Derivative financial instruments		9,963			—
Deferred income taxes		—			2,411
Debt issuance costs, net of accumulated amortization		30,635			33,479
Total Other Assets		40,598			35,890
Total Assets	$	2,944,982		$	2,798,860
LIABILITIES
Current Liabilities
Accounts payable	$	150,596		$	163,741
Accrued liabilities		95,419			111,157
Notes payable		9,196			19,853
Asset retirement obligations		25,379			19,624
Derivative financial instruments		25,352			50,259
Current maturities of long-term debt		2,555			4,054
Total Current Liabilities		308,497			368,688
Long-term debt, less current maturities		1,029,009			1,109,333
Deferred income taxes		68,722			—
Asset retirement obligations		316,698			303,618
Derivative financial instruments		951			70,524
Other liabilities		6,234			—
Total Liabilities		1,730,111			1,852,163
Commitments and Contingencies (Note 14)
Stockholders’ Equity
Preferred stock, $0.001 par value, 7,500,000 shares authorized:
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at December 31, 2011 and June 30, 2011, respectively		—			—
5.625% Convertible perpetual preferred stock, 1,050,000 shares issued and outstanding at December 31, 2011 and June 30, 2011, respectively		1			1
Common stock, $0.005 par value, 200,000,000 shares authorized and 76,790,281 and 76,203,574 shares issued and 76,533,928 and 76,202,921 shares outstanding at December 31, 2011 and June 30, 2011, respectively		384			381
Additional paid-in capital		1,499,528			1,479,959
Accumulated deficit		(309,152	)		(465,160	)
Accumulated other comprehensive income (loss), net of income taxes		24,110			(68,484	)
Total Stockholders’ Equity		1,214,871			946,697
Total Liabilities and Stockholders’ Equity	$	2,944,982		$	2,798,860

 
 
See accompanying Notes to Consolidated Financial Statements

4

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

	Three Months Ended December 31,						Six Months Ended December 31,
	2011			2010			2011			2010
Revenues
Oil sales	$	309,347		$	146,539		$	556,264		$	262,369
Natural gas sales		31,231			27,414			69,197			55,584
Total Revenues		340,578			173,953			625,461			317,953
Costs and Expenses
Lease operating		74,134			44,446			145,167			88,599
Production taxes		1,174			716			3,348			1,410
Gathering and transportation		3,395			801			9,548			822
Depreciation, depletion and amortization		87,568			62,922			172,371			116,999
Accretion of asset retirement obligations		9,803			6,348			19,491			12,322
General and administrative		22,147			15,786			41,468			34,383
Loss (gain) on derivative financial instruments		4,371			(1,638	)		(6,001	)		(2,776	)
Total Costs and Expenses		202,592			129,381			385,392			251,759
Operating Income		137,986			44,572			240,069			66,194
Other Income (Expense)
Bridge loan commitment fees		—			(4,500	)		—			(4,500	)
Loss on retirement of debt		—			(5,184	)		—			(5,184	)
Other income		15			151			24			161
Interest expense		(28,363	)		(22,094	)		(55,551	)		(43,574	)
Total Other Expense		(28,348	)		(31,627	)		(55,527	)		(53,097	)
Income Before Income Taxes		109,638			12,945			184,542			13,097
Income Tax Expense		12,549			2,011			21,122			2,030
Net Income		97,089			10,934			163,420			11,067
Induced Conversion of Preferred Stock		—			19,796			—			19,796
Preferred Stock Dividends		3,706			2,426			7,412			4,420
Net Income (Loss) Attributable to Common Stockholders	$	93,383		$	(11,288	)	$	156,008		$	(13,149	)
Net Income (Loss) Per Share Attributable to Common Stockholders
Basic	$	1.22		$	(0.17	)	$	2.04		$	(0.23	)
Diluted	$	1.11		$	(0.17	)	$	1.88		$	(0.23	)
Weighted Average Number of Common Shares Outstanding
Basic		76,498			65,479			76,481			58,241
Diluted		87,227			65,479			87,138			58,241

 
 
See accompanying Notes to Consolidated Financial Statements

5

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

	Three Months Ended December 31,						Six Months Ended December 31,
	2011			2010			2011			2010
Cash Flows From Operating Activities
Net income	$	97,089		$	10,934		$	163,420		$	11,067
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		87,568			62,922			172,371			116,999
Deferred income tax expense		12,547			2,011			21,272			2,030
Change in derivative financial instruments
Proceeds from sale of derivative instruments		15,931			8,522			65,529			42,577
Other – net		(6,445	)		(7,515	)		(25,691	)		(16,214	)
Accretion of asset retirement obligations		9,803			6,348			19,491			12,322
Amortization of debt discount and premium		—			(40,383	)		—			(43,132	)
Amortization and write-off of debt issuance costs		1,882			2,492			3,705			4,254
Stock-based compensation		1,189			391			10,114			2,180
Payment of interest in-kind		—			2,225			—			2,225
Changes in operating assets and liabilities
Accounts receivable		(30,275	)		(48,371	)		(17,581	)		(39,971	)
Prepaid expenses and other current assets		4,067			9,883			(5,066	)		(2,278	)
Settlement of asset retirement obligations		(1,407	)		(29,311	)		(1,994	)		(34,618	)
Accounts payable and accrued liabilities		(96	)		19,354			(37,586	)		20,012
Net Cash Provided by (Used in) Operating Activities		191,853			(498	)		367,984			77,453
Cash Flows from Investing Activities
Acquisitions		(6,242	)		(1,013,003	)		(6,177	)		(1,013,011	)
Capital expenditures		(125,695	)		(65,090	)		(238,444	)		(128,625	)
Insurance payments received		5,692			—			6,472			—
Proceeds from the sale of properties		2,767			—			2,767			400
Other		(1,062	)		115			(808	)		83
Net Cash Used in Investing Activities		(124,540	)		(1,077,978	)		(236,190	)		(1,141,153	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs		310			555,773			9,456			560,903
Conversion of preferred stock to common		—			(11,912	)		—			(11,912	)
Dividends to shareholders		(3,706	)		(179	)		(7,412	)		(2,173	)
Proceeds from long-term debt		285,854			1,113,000			522,324			1,160,000
Payments on long-term debt		(288,084	)		(520,838	)		(604,318	)		(586,767	)
Payments for debt issuance costs and other		(759	)		(30,260	)		(855	)		(30,584	)
Net Cash Provided by (Used in) Financing Activities		(6,385	)		1,105,584			(80,805	)		1,089,467
Net Increase in Cash and Cash Equivalents		60,928			27,108			50,989			25,767
Cash and Cash Equivalents, beginning of period		18,468			12,883			28,407			14,224
Cash and Cash Equivalents, end of period	$	79,396		$	39,991		$	79,396		$	39,991

 
 
See accompanying Notes to Consolidated Financial Statements

6

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation

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

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

Principles of Consolidation and Reporting.   The accompanying unaudited 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 unaudited 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, 2011, as amended (the “2011 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

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

Presentation of Comprehensive Income.   The FASB has issued new guidance on the presentation of comprehensive income. This new guidance allows an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of

7

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Recent Accounting Pronouncements  – (continued)

other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. This guidance eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The new guidance does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. Components of comprehensive income are stated net of income tax at 35%, subject to evaluations for the need for a valuation allowance against any resulting deferred tax asset(s).

This new guidance will be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted.

Note 3 — Acquisitions and Dispositions

ExxonMobil Acquisition

On December 17, 2010, we closed on the acquisition of certain shallow-water Gulf of Mexico shelf oil and natural gas interests (the “ExxonMobil Properties”) from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). The ExxonMobil Acquisition was funded through a combination of cash on hand, including proceeds from common and preferred equity offerings (see “Note 10 — Stockholders’ Equity”), borrowings under our revolving credit facility and proceeds from the $750 million private placement by our operating subsidiary, EGC, of 9.25% Senior Notes.

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

The ExxonMobil Acquisition 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 final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 17, 2010 (in thousands):

	December 17, 2010 (As initially reported)			Measurement period adjustment		December 17, 2010 (As adjusted)
Oil and natural gas properties – evaluated	$	926,422		$	—	$	926,422
Oil and natural gas properties – unevaluated		289,711			—		289,711
Net working capital*		101			577		678
Asset retirement obligations		(204,512	)		—		(204,512	)
Cash paid	$	1,011,722		$	577	$	1,012,299

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

The above estimated fair values of assets acquired and liabilities assumed are based on the information that was available as of the acquisition date to estimate the fair value of the assets acquired and liabilities assumed. As of December 31, 2011, the Company’s measurement period adjustments are complete.

8

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 — Acquisitions and Dispositions  – (continued)

The following amounts of the ExxonMobil Properties’ revenue and earnings are included in our consolidated statement of operations for the six months ended December 31, 2011 and the summarized unaudited pro forma financial information for the six months ended December 31, 2010 assumes that the ExxonMobil Acquisition had occurred on July 1, 2010. These unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed the acquisition as of the earlier date or the results that will be attained in the future (in thousands):

	Revenue		Earnings(1)
ExxonMobil Acquisition properties from July 1, 2011 through December 31, 2011	$	268,355	$	193,214
ExxonMobil Acquisitions properties
Supplemental pro forma for July 1, 2010 through December 31, 2010		489,687		353,717

(1) Earnings includes revenue less production costs.

Sale of Certain Onshore Properties

In June 2011, we closed on the sale of certain onshore oil and natural gas properties for cash consideration of $39.6 million. Revenues and expenses related to the sold properties have been included in our results of operations through the closing dates. The proceeds were recorded as a reduction to our oil and gas properties with no gain or loss being recognized.

Below is a summary of net reduction to the full cost pool related to the sale (in thousands):

Cash received	$	39,625
Reduction of asset retirement obligation related to properties		16,626
Net revenues from June 1, 2011 through closing date		(1,630	)
Adjustment to gas imbalances related to properties		36
Net reduction to the full cost pool	$	54,657

Note 4 — Property and Equipment

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

	December 31, 2011		June 30, 2011
Oil and natural gas properties
Proved properties	$	3,995,418	$	3,810,293
Less: Accumulated depreciation, depletion, amortization and impairment		1,903,236		1,732,250
Proved properties		2,092,182		2,078,043
Unproved properties		516,555		467,293
Oil and natural gas properties		2,608,737		2,545,336
Other property and equipment		20,482		18,354
Less: Accumulated depreciation		11,457		10,153
Other property and equipment		9,025		8,201
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	2,617,762	$	2,553,537

9

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt

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

	December 31, 2011		June 30, 2011
Revolving credit facility	$	28,478	$	107,784
9.25% Senior Notes due 2017		750,000		750,000
7.75% Senior Notes due 2019		250,000		250,000
Put premium financing		2,238		4,926
Capital lease obligation		848		677
Total debt		1,031,564		1,113,387
Less current maturities		2,555		4,054
Total long-term debt	$	1,029,009	$	1,109,333

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

Twelve Months Ending December 31,
2012	$	2,555
2013		340
2014		28,669
2015		—
2016		—
Thereafter		1,000,000
Total	$	1,031,564

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, EGC in May 2011. This facility has a borrowing capacity of $925 million and matures December 31, 2014. Borrowings are limited to a borrowing base based on oil and gas reserve values which are redetermined on a periodic basis. As at December 31, 2011, the current borrowing base was $750 million, which was unanimously reaffirmed by the lenders on September 14, 2011. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.25% to 3.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves.

EGC is prohibited from paying dividends to us except that EGC may make payments to us of up to $25 million in aggregate (including those in the aggregate total amount of $11,082,156 made to date) for the purpose of paying premiums or other payments associated with the early conversion of our preferred stock and EGC may make payments of up to $17 million in any calendar year, subject to certain terms and conditions, so that we may pay dividends on our outstanding preferred stock. On October 4, 2011, EGC entered into the First Amendment (the “First Amendment”) to the First Lien Credit Agreement which provided for increased flexibility to pay dividends or make loans from EGC to us and/or our other subsidiaries. The First Amendment modified the First Lien Credit Agreement and includes the following: (a) approval for cash distributions of up to $100 million per calendar year, which can be used for various purposes, including stock buybacks, bond repurchases, and /or debt repayments, and is based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds, and (b) approval of a cash distribution basket of up to an aggregate of $150 million, to be used for investments and other purposes based upon the Company meeting minimum liquidity and maximum revolver utilization thresholds. Both distribution baskets are further limited by an amount equal to $70 million plus 50% of our Consolidated Net Income (as defined in the First Amendment) for the period from October 1, 2010 through the most recently ended quarter.

10

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt  – (continued)

The First Amendment also increased the amount of borrowing base availability that must be reserved to deal with potential effects from hurricanes during the period of July 1^st to October 31^st of each calendar year from $25 million to $50 million.

The First Lien Credit Agreement 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 December 31, 2011, 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 face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act of 1933, as amended (the “Securities Act”), on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes was 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 in connection with the issuance of the 9.25% Old Senior Notes which have been capitalized and will be amortized over the life of the 9.25% Senior 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 as defined in the indenture governing the 9.25% Senior Notes.

The 9.25% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. We and our subsidiaries, other than EGC, have no significant independent assets or operations. EGC is prohibited from declaring or paying any dividend in excess of $70 million plus 50% of the consolidated net income of EGC for the period from October 1, 2010, subject to certain other adjustments and exceptions.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of December 31, 2011 was $818.4 million.

7.75% Senior Notes

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

11

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — 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 in connection with the issuance of the 7.75% Old Senior Notes which have been capitalized and will be amortized over the life of the 7.75% Senior 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 as defined in the indenture governing the 7.75% Senior Notes.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries. Our indirect, wholly-owned subsidiary, EGC, is the issuer of the 7.75% Senior Notes which are fully and unconditionally guaranteed by us. We and our subsidiaries, other than EGC, have no significant independent assets or operations. EGC is prohibited from declaring or paying any dividend in excess of $70 million plus 50% of the consolidated net income of EGC for the period from October 1, 2010, subject to certain other adjustments and exceptions.

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of December 31, 2011 was $257.5 million.

Put Premium Financing

We finance premiums on puts that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Put premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The put premium financing is structured to mature when the put settles so that we realize the value net of put premium financing. As of December 31, 2011 and June 30, 2011, our outstanding put premium financing totaled $2.2 million and $4.9 million, respectively.

12

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt  – (continued)

Interest Expense

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

	Three Months Ended December 31,					Six Months Ended December 31,
	2011		2010			2011		2010
Revolving credit facility	$	2,270	$	1,456		$	5,090	$	2,897
9.25% Senior Notes due 2017		17,343		2,505			34,687		2,505
7.75% Senior Notes due 2019		4,844		—			9,688		—
10% Senior Notes due 2013		—		6,912			—		13,825
16% Second Lien Notes due 2014		—		11,286			—		24,967
Amortization of debt issue cost – Revolving credit facility		1,233		1,381			2,407		2,525
Amortization of debt issue cost – 10% Senior Notes due 2013		—		589			—		1,178
Amortization of debt issue cost – 16% Second Lien Notes due 2014		—		25			—		54
Amortization of debt issue cost – 9.25% Senior Notes due 2017		551		92			1,103		92
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97		—			194		—
Discount amortization – 16% Second Lien Notes due 2014 (Private Placement)		—		(3,098	)		—		(6,889	)
Premium amortization – 16% Second Lien Notes due 2014 (Exchange Offer)		—		852			—		1,894
Put premium financing and other		135		94			492		526
Settlement of Lehman Brothers liability		1,890		—			1,890		—
	$	28,363	$	22,094		$	55,551	$	43,574

Bridge Loan Commitment Fee

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

Note 6 — Notes Payable

In May 2011, we entered into a note with Bank Direct Capital Finance, LLC to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.93%. The note amortizes over ten months. The balance outstanding as of December 31, 2011 and June 30, 2011 was $6.6 million and $19.9 million, respectively.

In July 2011, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note is for a total face amount of $6.3 million and bears interest at an annual rate of 1.93%. The note amortizes over the remaining term of the insurance, which matures May 1, 2012. The balance outstanding as of December 31, 2011 was $2.6 million.

13

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 — Asset Retirement Obligations

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

Balance at June 30, 2011	$	323,242
Liabilities incurred		1,338
Liabilities settled		(1,994	)
Accretion expense		19,491
Total balance at December 31, 2011		342,077
Less current portion		25,379
Long-term balance at December 31, 2011	$	316,698

Note 8 — Derivative Financial Instruments

We enter into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. The Company designates a majority of its 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 the Company discontinues 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 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. 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.

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.

14

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

We have monetized certain hedge positions and received the following cash proceeds in the following quarters (in thousands):

Quarter Ended	Cash Proceeds
March 31, 2009	$	66,500
March 31, 2010		5,000
September 30, 2010		34,100
December 31, 2010		8,500
September 30, 2011		49,600
December 31, 2011		16,800
	$	180,500

These above monetized amounts were recorded in stockholders’ equity as part of other comprehensive income and are recognized in income over the contract life of the underlying hedge contracts. An additional $0.8 million monetization was captured in the September 30, 2011 quarter with the cash to be received when the underlying hedge contract settles during calendar 2013.

Our future crude oil and natural gas revenue will be increased by the following amounts related to the monetized contracts referred to above (in thousands):

Quarter Ended	Cash(1)		Non-Cash(1)		Total
March 31, 2012	$	10,546	$	—	$	10,546
June 30, 2012		11,023		—		11,023
September 30, 2012		8,532		—		8,532
December 31, 2012		8,040		—		8,040
Thereafter		19,449		825		20,274
	$	57,590	$	825	$	58,415

(1) Cash represents the amounts received as of December 31, 2011 as part of the monetization of certain hedge contracts. Non-cash represents monetized hedges in which the cash will be received when the underlying hedge contract settles in calendar 2013.

15

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

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

Crude Oil											Natural Gas
					Total										Total					Total
Period	Volume (MBbls)		Contract Price(1)		Asset (Liability)			Fair Value (Gain) Loss			Volume (MMMBtus)		Contract Price(1)		Asset (Liability)		Fair Value (Gain) Loss			Asset (Liability)			Fair (Gain) Loss(2)
WTI Commodity Collars
1/12 – 12/12		2,818	$	72.60/$100.19	$	(18,797	)	$	12,218			1,840	$	4.50/$5.35	$	2,158	$	(1,403	)	$	(16,639	)	$	10,815
1/13 – 12/13		1,278		73.57/105.63		(4,203	)		2,732												(4,203	)		2,732
						(23,000	)		14,950							2,158		(1,403	)		(20,842	)		13,547
Brent Commodity Collars
1/12 – 12/12		1,830		87.00/114.24		(4,567	)		2,959												(4,567	)		2,959
1/13 – 12/13		3,103		80.00/126.78		2,602															2,602
						(1,965	)		2,959												(1,965	)		2,959
Three-Way Collars
1/12 – 12/12		4,465		66.93/86.93/133.55		(2,521	)		3,283			5,520		4.07/4.93/5.87		3,968		(2,580	)		1,447			703
1/13 – 12/13		1,643		61.67/83.33/140.69		2,906			(123	)		10,950		4.07/4.93/5.87		5,719		(3,717	)		8,625			(3,840	)
1/14 – 12/14		1,095		65.00/85.00/140.00		1,987															1,987
						2,372			3,160							9,687		(6,297	)		12,059			(3,137	)
Total (Gain) Loss on Derivatives					$	(22,593	)	$	21,069						$	11,845	$	(7,700	)	$	(10,748	)	$	13,369

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

(2) The loss on derivative contracts is net of applicable income taxes.

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

	Asset Derivative Instruments								Liability Derivative Instruments
	As of December 31, 2011				As of June 30, 2011				As of December 31, 2011				As of June 30, 2011
	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	$	43,165		Current	$	6,048		Current	$	62,925		Current	$	58,593
		Non-Current		68,848		Non-Current		1,248		Non-Current		59,836		Non-Current		72,719
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		—		Current		2,310		Current		—		Current		3
		Non-Current		—		Non-Current		948		Non-Current		—		Non-Current		—
Total			$	112,013			$	10,554			$	122,761			$	131,315

16

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

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

	Three Months Ended December 31,						Six Months Ended December 31,
Location of (gain) loss in Income Statement	2011			2010			2011			2010
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(3,283	)	$	9,734		$	(433	)	$	12,167
Natural gas sales		(9,571	)		(9,113	)		(19,400	)		(17,839	)
Total cash settlements		(12,854	)		621			(19,833	)		(5,672	)
Commodity Derivative Instruments designated as hedging instruments:
Loss (gain) on derivative financial instruments Ineffective portion of commodity derivative instruments		5,094			(266	)		(1,674	)		215
Commodity Derivative Instruments not designated as hedging instruments:
Loss (gain) on derivative financial instruments Realized mark to market gain		(1,615	)		(1,840	)		(5,025	)		(3,226	)
Loss (gain) on derivative financial instruments Unrealized mark to market loss		892			468			698			235
Total loss (gain) on derivative financial instruments		4,371			(1,638	)		(6,001	)		(2,776	)
Total gain	$	(8,483	)	$	(1,017	)	$	(25,834	)	$	(8,448	)

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

	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)
Location of (gain) loss	2011			2010			2011			2010			2011			2010
Three Months Ended December 31,
Commodity Derivative Instruments	$	31,320		$	(57,880	)	$	—		$	—		$	—		$	—
Revenues		—			—			(8,460	)		(478	)		—			—
Loss (gain) on derivative financial instruments		—			—			—			—			5,094			(266	)
Total	$	31,320		$	(57,880	)	$	(8,460	)	$	(478	)	$	5,094		$	(266	)
Six Months Ended December 31,
Commodity Derivative Instruments	$	(92,594	)	$	(68,123	)	$	—		$	—		$	—		$	—
Revenues		—			—			(14,812	)		(366	)		—			—
Loss (gain) on derivative financial instruments		—			—			—			—			(1,674	)		215
Total	$	(92,594	)	$	(68,123	)	$	(14,812	)	$	(366	)	$	(1,674	)	$	215

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

17

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 — Derivative Financial Instruments  – (continued)

Comprehensive income includes net income and certain items recorded directly in Stockholders’ equity and classified as accumulated other comprehensive income. Comprehensive income (loss) was calculated as follows (in thousands):

	Three Months Ended December 31,						Six Months Ended December 31,
	2011			2010			2011			2010
Net income	$	97,089		$	10,934		$	163,420		$	11,067
Other comprehensive income (loss), net of tax:
Oil and gas cash flow hedges
Unrealized change in fair value including monetized hedges		(22,860	)		(57,402	)		107,406			(67,757	)
Reclassified to earnings during the period		(8,460	)		(478	)		(14,812	)		(366	)
Other comprehensive income (loss), net of tax:		(31,320	)		(57,880	)		92,594			(68,123	)
Comprehensive income (loss)	$	65,769		$	(46,946	)	$	256,014		$	(57,056	)

The amount expected to be reclassified to income in the next 12 months is a gain of $15.9 million on our commodity hedges.

Note 9 — Income Taxes

We are a Bermuda company and we are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. 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 11.45%. The significant variance from the U.S. statutory rate is primarily due to the change in the valuation allowance (discussed below) against the U.S. net deferred tax assets and the accrual of the U.S. withholding obligation related to the interest income payable to the Bermuda Companies which may not be offset by other U.S. tax attributes. Our Bermuda Companies continue to report a tax provision reflecting accrued 30% U.S. withholding tax required on any interest payments made from the U.S. Companies to the Bermuda Companies. We have accrued a withholding obligation of $5.2 million for the six months ended December 31, 2011.

During the year ended June 30, 2009, we incurred a significant impairment loss related to our oil and gas properties due to the steep decline in global energy prices over that same time period. As a result of this impairment, we were in a position of cumulative reporting losses for the preceding reporting periods. The volatility of energy prices since has been problematic and not readily determinable by our management. Under these circumstances, it has been management’s opinion that the realization of our tax attributes beyond expected current-year taxable income (including the reversal of existing taxable temporary differences and the resolution of certain hedging activity) does not reach the “more likely than not” criteria under ASC 740 (formerly known as FAS 109). As a result, during the year ended June 30, 2009, we established a valuation allowance of $175.0 million, but have subsequently reduced the valuation allowance due to the presence of actual earnings reported in quarters since establishment of the allowance. If current indications of pre-tax earnings for the year prove to be correct, we will release approximately $90 million of our remaining valuation allowance during this fiscal year (which has been reflected in the estimated annual effective tax rate indicated above). While the Company has not made significant income tax payments in recent years, in light of expected income in this fiscal year, estimated tax payments in subsequent quarters may be required in amounts yet to be determined in accordance with the applicable federal income tax provisions related to required corporate estimated tax payments.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — 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.

November 2010 Common Equity Offering

On November 3, 2010, we closed on concurrent offerings of common and preferred stock. We sold 12 million shares of our unrestricted common stock at $20.75 per share less $0.985 per share in underwriting commissions. Net proceeds from the common stock offering were approximately $237.2 million, after deducting underwriting commissions, but before other offering expenses.

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

Preferred Stock

Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. The number of authorized preferred shares we are authorized to issue was increased to 7,500,000 shares from 2,500,000 shares, and approved by shareholders at the Annual General Meeting held in November 2011. 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.

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

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

November 2010 5.625% Perpetual Convertible Preferred Stock Offering

On November 3, 2010, we sold 1.15 million shares of 5.625% Preferred Stock at $250 per share, less $3.75 per share (1.5%) in underwriting commissions. Net proceeds to the Company from the sale of preferred stock were approximately $283.2 million, after deducting underwriting commissions, but before other offering expenses.

19

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 — Stockholders’ Equity  – (continued)

Conversion of Preferred Stock

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

During the year ended June 30, 2011, we entered into other private transactions with third parties related to the conversion of our 7.25% Preferred Stock. In addition to the stated conversion of 8.77192 common shares per preferred share, we made additional payments in stock and cash to induce the conversion.

During May and June 2011, we cancelled and converted a total of 100,000 shares of our 5.625% Preferred Stock into common stock. In addition to the stated conversion rate of 9.8353 common shares per preferred share, we also issued additional common shares to induce the conversion quantity.

At December 31, 2011, we have 1.05 million shares of 5.625% Preferred Stock and 8,000 shares of 7.25% Preferred Stock issued and outstanding.

Note 11 — Supplemental Cash Flow Information

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

	Three Months Ended December 31,				Six Months Ended December 31,
	2011		2010		2011		2010
Cash paid for interest	$	46,768	$	40,146	$	52,023	$	42,276

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

	Three Months Ended December 31,					Six Months Ended December 31,
	2011		2010			2011		2010
Financing of insurance premiums	$	8,517	$	6,534		$	9,196	$	6,574
Conversion of preferred stock to common		—		(7,884	)		—		(7,884	)
Preferred stock dividends		618		2,246			618		2,246
Additions to property and equipment by recognizing asset retirement obligations		794		206,117			1,338		207,167

Note 12 — Employee Benefit Plans

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

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

Performance Units

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

At our discretion, at the time the Phantom Stock Units and Performance Based Units vest, employees will settle in either common shares or cash. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Phantom Stock Units and Performance Based Units become immediately vested and payable. Historically, we have paid all vesting awards in cash. The July 21, 2011 vesting of the July 21, 2010 and 2009 Performance Based Unit awards were paid 50% in common stock and future vesting of the Performance Based Units may be paid in stock at the discretion of our board of directors.

As of December 31, 2011, we have 965,221 unvested Phantom Stock units and 3,891,438 unvested Performance Units. For the three months and six months ended December 31, 2011 and 2010, we recognized compensation expense (benefit) of $6.7 million, $5.0 million, $10.1 million and $8.7 million, respectively, related to our Phantom Stock Units. For the three months and six months ended December 31, 2011 and 2010, we recognized compensation expense of $9.6 million, $6.0 million, $17.0 million and $13.9 million, respectively, related to our Performance Units. A liability has been recognized as of December 31, 2011 in the amount of $22.5 million, in accrued liabilities in the accompanying consolidated balance sheet. The amount of the liability will be remeasured as of each reporting date at fair value, which is based on period-end stock price for our Phantom Stock units and for our Time-Based Performance Units and the results of the Monte Carlo simulation model which we use for our performance-based performance units.

Restricted Shares

Restricted Shares activity is as follows:

	Number Of Shares			Grant-date Fair value Per Share
Non-vested at June 30, 2011		31,214		$	24.75
Vested during the six months ended December 31, 2011		(31,214	)
Non-vested at December 31, 2011		—

We determine the fair value of the Restricted Shares based on the market price of our Common Stock on the date of grant. Compensation cost for the Restricted Shares is recognized on a straight line basis over the requisite service period. For the three months and six months ended December 31, 2011 and 2010, we recognized compensation expense of $0, $0.2 million, $49,000 and $0.6 million, respectively, related to our Restricted Shares.

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 six months ended December 31, 2011 and 2010, we issued 272,579 shares and 243,160 shares, respectively, under the 2008 Purchase Plan.

21

ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12 — Employee Benefit Plans  – (continued)

In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the period. The current period is from July 1, 2011 to December 31, 2011. For the three months and six months ended December 31, 2011 and 2010, we had charged $143,000, $94,000, $301,000 and $189,000, respectively, to compensation expense related to this plan. During the six months ended December 31, 2011 and 2010, we issued 21,015 shares and 84,077 shares, respectively, under the Employee Stock Purchase Plan. The Employee Stock Purchase Plan has a limit of 1,000,000 common shares.

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 December 31, 2011, 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:

	Six Months Ended December 31,
	2011					2010
	Unvested Shares Under Option			Weighted Ave. Exercise Price		Unvested Shares Under Option			Weighted Ave. Exercise Price
Beginning balance – unvested options		100,000		$	17.50		240,000		$	17.50
Vested		(100,000	)		17.50		(140,000	)		17.50
Ending balance – unvested options		—		$	17.50		100,000		$	17.50

Our net income for the three and six months ended December 31, 2011 and 2010 includes expense of approximately $0, $88,000, $58,000 and $596,000, respectively, 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 cost to us under these plans for the three months ended December 31, 2011 and 2010 was $0.9 million for profit sharing and $0.5 million for the 401 (k) Plan and $0.6 million for profit sharing and $0.2 million for the 401 (k) Plan, respectively. The cost to us under these plans for the six months ended December 31, 2011 and 2010 was $1.8 million for profit sharing and $1.5 million for the 401 (k) Plan and $1.2 million for profit sharing and $1.1 million for the 401 (k) Plan, respectively.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 — Earnings per Share

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

	Three Months Ended December 31,					Six Months Ended December 31,
	2011		2010			2011		2010
Net income	$	97,089	$	10,934		$	163,420	$	11,067
Preferred stock dividends		3,706		2,426			7,412		4,420
Induced Conversion of Preferred Stock		—		19,796			—		19,796
Net income (loss) available for common stockholders	$	93,383	$	(11,288	)	$	156,008	$	(13,149	)
Weighted average shares outstanding for basic EPS		76,498		65,479			76,481		58,241
Add dilutive securities		10,729		—			10,657		—
Weighted average shares outstanding for diluted EPS		87,227		65,479			87,138		58,241
Net income (loss) per share attributable to common stockholders
Basic	$	1.22	$	(0.17	)	$	2.04	$	(0.23	)
Diluted	$	1.11	$	(0.17	)	$	1.88	$	(0.23	)

For the three months and six months ended December 31, 2010, 543,478 and 608,696 common stock equivalents, respectively, were excluded from the diluted average shares due to an anti-dilutive effect.

Note 14 — Commitments and Contingencies

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

Lease Commitments.   We have non-cancelable operating leases for office space and other that principally expire on December 31, 2018. Future minimum lease commitments as of December 31, 2011 under the operating lease are as follows (in thousands):

Twelve Months Ending December 31,
2012	$	2,185
2013		2,136
2014		1,756
2015		1,756
2016		1,840
Thereafter		2,351
Total	$	12,024

Rent expense, including rent incurred on short-term leases, for the three months and six months ended December 31, 2011 and 2010 was approximately $358,000, $464,000, $896,000 and $946,000, respectively.

Letters of Credit and Performance Bonds.   We had $231.5 million in letters of credit and $25.1 million of performance bonds outstanding as of December 31, 2011.

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Commitments and Contingencies  – (continued)

Drilling Rig Commitments.   As of December 31, 2011, we have entered into four drilling rig commitments, the first of which commenced on July 3, 2011 at $42,500 per day for one well until well completion. The second commitment commenced on October 1, 2011 at $65,000 per day for six months. The third commenced on November 4, 2011 at $47,800 per day for four wells until well completion with options to do additional work. The last one commenced on December 10, 2011 at $44,500 per day for one well until well completion. Since the preceding commitments are not finished and extend past December 31, 2011, the commitment amounts cannot be calculated since the well completion dates are not known.

Note 15 — 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 as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. In addition, for collars, we estimate the option values using an option pricing model which takes into account market volatility, market prices and contract terms. 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 8 —  Derivative Financial Instruments.

Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments. Our natural gas and oil derivatives are classified as described below:

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

The fair value of our financial instruments was as follow (in thousands):

	Level 2
	As of December 31, 2011		As of June 30, 2011
Assets:
Oil and Natural Gas Derivatives		15,555		22
Liabilities:
Oil and Natural Gas Derivatives		26,303		120,783

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ENERGY XXI (BERMUDA) LIMITED
  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 — Prepayments and Accrued Liabilities

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

	December 31, 2011		June 30, 2011
Prepaid expenses and other current assets
Advances to joint interest partners	$	22,774	$	14,696
Insurance		13,678		23,230
Inventory		6,207		6,305
Royalty deposit		2,443		1,959
Short-term stock investment		6,755		—
Other		960		1,561
Total prepaid expenses and other current assets	$	52,817	$	47,751
Accrued liabilities
Advances from joint interest partners	$	1,322	$	437
Employee benefits and payroll		21,633		53,789
Interest		3,736		5,806
Accrued hedge payable		11,425		14,095
Undistributed oil and gas proceeds		50,449		31,880
Other		6,854		5,150
Total accrued liabilities	$	95,419	$	111,157

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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: (a) acquiring producing oil and gas properties; (b) exploiting and exploring our core assets to enhance production and ultimate recovery of reserves; and (c) utilizing a portion of our capital program to explore the ultra-deep Gulf of Mexico shelf for potential oil and gas reserves.

Our operations are geographically focused and we target acquisitions of oil and gas properties in which we believe we can add value by increasing production and ultimate recovery of reserves, either through exploitation or exploration activities, often using reprocessed seismic data to identify previously overlooked opportunities. For the year ended June 30, 2011, excluding acquisitions, approximately 64% of our capital expenditures were associated with the exploitation of existing properties.

At December 31, 2011, we operated or had an interest in 419 gross producing wells on 254,891 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 our operated fields efficiently and our high number of wellbore locations provides us with diversification in our production and reserves. We believe operating our assets is a key component to our strategy, and approximately 83% of our proved reserves are on properties operated by us. We have historically focused on oil-weighted projects and acquisitions, and as a result, our proved reserves were 66% oil as of June 30, 2011, and our production was 72% oil for the quarter ending December 31, 2011. We also have a seismic database covering approximately 5,150 square miles, primarily focused on our existing operations. This database has helped us to initially identify approximately 190 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 additional exploration opportunities on these 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 this disciplined risk management strategy provides substantial price protection, as our cash flow on the hedged portion is driven by our production results rather than commodity prices. We believe this greater price certainty allows us to more efficiently manage our cash flows and effectively 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, 2010 and 2011 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 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.

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, could involve 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.

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Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. As required by our revolving credit facility, we have mitigated this volatility through December 2013 by implementing a hedging program on a portion of our total anticipated production during this time frame. See Note 8 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 as is currently being experienced in the natural gas market. 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. We do not anticipate an out-of-cycle borrowing base redetermination as a result of low natural gas prices and expect our next redetermination to occur as scheduled in the spring of 2012.

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. Increased regulation in a number of areas could disrupt, delay or prohibit future drilling programs and ultimately impact the fair value of our unevaluated properties. As of December 31, 2011, we have approximately $180 million of investments in unevaluated oil and gas properties related to ultra-deep shelf exploration. If the fair value of these investments were to fall below the recorded amounts, the excess would be transferred to evaluated oil and gas properties thereby affecting the computation of amounts for depreciation, depletion and amortization and potentially our ceiling test computation. As of December 31, 2011, the computation of our ceiling test indicated a cushion of approximately $1.6 billion.

Operational Highlights

Ultra-Deep Shelf Exploration and Development Activity

We participate in a joint venture (the “Partnership”) led by McMoRan Exploration Company with respect to several prospects in the ultra-deep shelf in the Gulf of Mexico. Data received to date from ultra-deep shelf drilling with respect to the Davy Jones and Blackbeard West discovery wells in the Gulf of Mexico confirm geologic modeling that correlates objective sections on the shelf below the salt weld in the Miocene and older age sections to those productive sections seen in deepwater discoveries by other industry participants. In addition to Davy Jones and Blackbeard West, the Partnership has identified approximately 15 ultra-deep shelf prospects in shallow water near existing infrastructure. The Partnership’s ultra-deep shelf drilling plans in calendar years 2010 thru 2012 included the Blackbeard East and Lafitte exploratory wells and delineation drilling at Davy Jones. The Partnership’s near-term sub-salt shelf drilling plans include 2 to 3 exploratory wells. We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep shelf exploration and development activity.

Davy Jones.  In January 2010, the Davy Jones discovery well on South Marsh Island Block 230 (“Davy Jones #1”) was drilled to a total depth of 29,000 feet. As reported in January 2010, the Partnership logged 200 net feet of pay in multiple Eocene/Paleocene (Wilcox) sands in the well. Completion activities of the

27

Davy Jones No. 1 discovery well at South Marsh Island Block 230 are in the advanced stages as the wellbore has been cleaned out to total depth and oil based drilling mud is currently being displaced with completion fluid. Remaining steps include running a pulsed neutron log, running perforating guns and production tubing in the hole, removing the blowout preventers and installing the production tree. McMoRan will then pressure up the tubing to activate and fire the perforating guns in the hole to flow test the well. The production tree, blow out preventer and safety valve are rated for pressures of 25,000 pounds per square inch. Installation of the central processing facility, production platform for Davy Jones No. 1 well and sales pipelines have been substantially completed. A successful flow test would have important implications on potential future reserve additions at Davy Jones and other ultra-deep prospects. Following a successful flow test, EXXI expects that the well will be connected to the facilities that are already in place and first production from the well would be established shortly thereafter.

On April 7, 2010, the Partnership commenced drilling the Davy Jones offset appraisal well (“Davy Jones #2”) on South Marsh Island Block 234, two and a half miles southwest of Davy Jones #1. The well has been drilled to a total depth of 30,546 and a 6 5/8” liner was set to TD and the well was suspended awaiting completion. As previously reported, log results above 27,300 feet confirmed 120 net feet of hydrocarbon- bearing Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect. Davy Jones #2 encountered the same Wilcox sand sections that were encountered in the Davy Jones #1, in addition to Tuscaloosa and Cretaceous sections that were encountered deeper in the well. In June 2011, results from wireline logs of the Cretaceous section below 27,300 feet indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. The well has been temporarily abandoned pending completion and facilities installation, which is expected to occur in the first half of fiscal 2013.

The Davy Jones play involves a large ultra-deep shelf structure encompassing four lease blocks (20,000 acres). As of December 31, 2011, our investment in both wells at Davy Jones totaled about $77 million.

Blackbeard East.  The Blackbeard East ultra-deep shelf exploration well commenced drilling on March 8, 2010 and was drilled to a depth of 32,559 feet. The drill pipe became stuck and upon attempting to retrieve the pipe 1,351 feet of pipe was left in the bottom of the hole. In July 2011, McMoRan commenced operations to drill a by-pass of the well at approximately 30,700 feet to evaluate targets in the Eocene. The by-pass well, which is permitted to 34,000 feet, has been drilled to 33,318 feet true vertical depth (TVD) (33,882 feet measured depth) and logging operations for the section below 30,800 feet are under way. As reported in January 2011, wireline logs indicated that Blackbeard East encountered hydrocarbon bearing sands in the Oligocene (Frio) with good porosity below 30,000 feet. The well previously encountered 178 net feet of hydrocarbons in the Miocene sands above 25,000 feet and downdip potential in the Oligocene (Frio) below 30,000 feet. 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. Blackbeard East is located in 80 feet of water on South Timbalier Block 144. As of December 31, 2011, our investment in the well totaled about $42 million.

Lafitte.  The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is drilling below 33,000 to a proposed total depth of 34,000 feet to evaluate additional Oligocene objectives. Recent wireline logs have indicated hydrocarbon bearing sands in the Oligocene (Frio) section below 30,000 feet. This is the second hydrocarbon bearing Frio sand section encountered either on the GOM Shelf or in the deepwater offshore Louisiana. The first Frio sand was seen approximately 80 miles east in McMoRan’s Blackbeard East well below 30,000 feet. McMoRan is considering additional drilling opportunities on the Lafitte structure to evaluate this section further. As previously reported, wireline logs from interim logging operations have indicated 211 net feet of possible productive sands in the Lafitte well, including 56 net feet of hydrocarbon bearing sand in the Cris-R section of the Lower Miocene and 40 net feet in the Frio section. Flow testing will be required to confirm the ultimate hydrocarbon flow rates from this zone, which was full to base. As of December 31, 2011, our investment in the well totaled about $31 million.

Blackbeard West.  Information gained from the Blackbeard East and Lafitte wells will enable the Partnership to consider priorities for future operations at Blackbeard West. As previously reported, the

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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 BOEMRE had granted a geophysical Suspension of Operations (“SOO”) to extend the terms of Blackbeard West leases through April 30, 2012 allowing the Partnership to drill an offset location. The Blackbeard West #2 which commenced drilling on November 25, 2011 and is currently drilling below 15,450 feet towards a proposed total depth of 26,000 feet is located on Ship Shoal Block 188 within the Blackbeard West unit, is targeting Miocene aged sands seen below the salt weld approximately 13 miles east at Blackbeard East. Our investment in both Blackbeard West wells totaled about $31 million at December 31, 2011.

Known Trends and Uncertainties

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 Bureau of Safety and Environmental Enforcement (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 Gulf of Mexico 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.

Ultra-Deep Shelf Exploration and Development.  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, the Partnership has identified approximately 15 additional ultra-deep shelf prospects in shallow water near existing infrastructure. We expect to have sufficient cash flow from operations to fund our current commitments related to our ultra-deep shelf exploration and development activity in 2012. We have participated in six wells to date with our interest ranging from approximately 16% to 20% per well. Of these wells, one is pending further evaluation and five are in process. We target to spend less than 15% of our cash flow on our exploration activities on the ultra-deep shelf. Of the six wells with activity to date, one has been temporarily abandoned pending further evaluation, two are temporarily abandoned pending facilities and completions later this fiscal year and three are currently drilling. Based on the results of these wells, our proved reserves may vary from our current 66% oil composition.

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Operational Information (In thousands except for unit amounts)

	Quarter Ended
Operating Highlights	Dec. 31, 2011			Sept. 30, 2011			June 30, 2011			Mar. 31, 2011			Dec. 31, 2010
Operating revenues
Crude oil sales	$	306,064		$	249,767		$	270,252		$	233,081		$	156,273
Natural gas sales		21,659			28,138			31,875			32,193			18,301
Hedge gain (loss)		12,855			6,978			(19,346	)		(6,638	)		(621	)
Total revenues		340,578			284,883			282,781			258,636			173,953
Percent of operating revenues from crude oil
Prior to hedge gain (loss)		93	%		90	%		89	%		88	%		90	%
Including hedge gain (loss)		91	%		87	%		85	%		84	%		84	%
Operating expenses
Lease operating expense
Insurance expense		7,096			7,462			8,814			6,543			6,376
Workover and maintenance		12,805			6,653			17,251			4,121			4,105
Direct lease operating expense		54,233			56,918			59,557			54,593			33,965
Total lease operating expense		74,134			71,033			85,622			65,257			44,446
Production taxes		1,174			2,174			1,205			721			716
Gathering and transportation		3,395			6,153			6,868			4,809			801
DD&A		87,568			84,803			85,179			91,301			62,922
General and administrative		22,147			19,321			17,553			23,155			15,786
Other – net		14,174			(684	)		7,730			9,288			4,710
Total operating expenses		202,592			182,800			204,157			194,531			129,381
Operating income	$	137,986		$	102,083		$	78,624		$	64,105		$	44,572
Sales volumes per day
Natural gas (MMcf)		72.8			77.0			83.0			84.6			53.7
Crude oil (MBbls)		30.6			28.0			28.3			27.3			20.4
Total (MBOE)		42.7			40.8			42.1			41.4			29.4
Percent of sales volumes from crude oil		72	%		69	%		67	%		66	%		70	%
Average sales price
Natural gas per Mcf	$	3.23		$	3.97		$	4.22		$	4.23		$	3.70
Hedge gain per Mcf		1.43			1.39			1.37			1.28			1.85
Total natural gas per Mcf	$	4.66		$	5.36		$	5.59		$	5.51		$	5.55
Crude oil per Bbl	$	108.80		$	97.11		$	105.12		$	94.94		$	83.14
Hedge gain (loss) per Bbl		1.17			(1.11	)		(11.53	)		(6.67	)		(5.18	)
Total crude oil per Bbl	$	109.97		$	96.00		$	93.59		$	88.27		$	77.96
Total hedge gain (loss) per BOE	$	3.27		$	1.86		$	(5.05	)	$	(1.78	)	$	(0.23)

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	Quarter Ended
Operating Highlights	Dec. 31, 2011		Sept. 30, 2011			June 30, 2011		Mar. 31, 2011		Dec. 31, 2010
Operating revenues per BOE	$	86.67	$	75.91		$	73.85	$	69.46	$	64.34
Operating expenses per BOE
Lease operating expense
Insurance expense		1.81		1.99			2.30		1.76		2.36
Workover and maintenance		3.26		1.77			4.51		1.11		1.52
Direct lease operating expense		13.80		15.17			15.55		14.66		12.56
Total lease operating expense		18.87		18.93			22.36		17.53		16.44
Production taxes		0.30		0.58			0.31		0.19		0.26
Gathering and transportation		0.86		1.64			1.79		1.28		0.29
DD&A		22.28		22.60			22.24		24.52		23.27
General and administrative		5.64		5.15			4.58		6.22		5.84
Other – net		3.60		(0.18	)		2.01		2.49		1.74
Total operating expenses		51.55		48.72			53.29		52.23		47.84
Operating income per BOE	$	35.12	$	27.19		$	20.56	$	17.23	$	16.50

Results of Operations

Three Months Ended December 31, 2011 Compared With the Three Months Ended December 31, 2010.

Our consolidated income available for common stockholders for the three months ended December 31, 2011 was $93.4 million or $1.11 diluted income per common share (“per share”) as compared to a consolidated net loss of $11.3 million or $0.17 diluted loss per share for the three months ended December 31, 2010. This improvement is primarily due to higher production volumes due to the ExxonMobil Acquisition coupled with higher crude oil prices partially offset by higher costs.

Price and Volume Variances

	Three Months Ended December 31,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decreae)
	2011			2010
													(In thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	109.97		$	77.96		$	32.01			41	%	$	90,071
Natural gas sales prices (per Mcf)		4.66			5.55			(0.89	)		(16	)%		(5,963	)
Total price variance														84,108
Volume Variance
Crude oil sales volumes (MBbls)		2,813			1,880			933			50	%		72,737
Natural gas sales volumes (MMcf)		6,700			4,943			1,757			36	%		9,780
BOE sales volumes (MBOE)		3,930			2,704			1,226			45	%
Percent of BOE from crude oil		72	%		70	%
Total volume variance														82,517
Total price and volume variance													$	166,625

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

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Revenue Variances

	Three Months Ended December 31,				Increase		Percent Increase
	2011		2010
			(In Thousands)
Crude oil	$	309,347	$	146,539	$	162,808		111	%
Natural gas		31,231		27,414		3,817		14	%
Total revenues	$	340,578	$	173,953	$	166,625		96	%

Revenues

Our consolidated revenues increased $166.6 million in the second quarter of fiscal 2012 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher crude oil and natural gas sales volumes as a result of the ExxonMobil Acquisition, coupled with higher crude oil 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. Higher overall commodity prices increased revenues by $84 million in the second quarter of fiscal 2012. Average crude oil prices, including a $1.17 realized gain per barrel related to hedging activities, increased $32.01 per barrel in the second quarter of fiscal 2012, resulting in increased revenues of $90 million. Average natural gas prices, including a $1.43 realized gain per Mcf related to hedging activities, decreased $0.89 per Mcf during the second quarter of fiscal 2012, resulting in decreased revenues of $6 million. Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during the second quarter of fiscal 2012 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash from operating activities, potentially causing us to expend less on our capital program. Lower spending on our capital program could result in a reduction of the amount of production volumes we are able to produce. We cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Higher total sales volumes in the second quarter of fiscal 2012 resulted in increased revenues of $83 million. Crude oil sales volumes increased 10.1 MBbls per day in the second quarter of fiscal 2012, resulting in increased revenues of $73 million. Natural gas sales volumes increased 19 MMcf per day in the second quarter of fiscal 2012, resulting in increased revenues of $10 million. The increase in crude oil and natural gas sales volumes in the second quarter of fiscal 2012 was primarily due to the ExxonMobil Acquisition.

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

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

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Costs and Expenses and Other (Income) Expense

	Three Months Ended December 31,											Increase (Decrease) Amount
	2011					2010
	Amount			Per BOE		Amount			Per BOE
	(In Thousands, except per unit amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	7,096		$	1.81	$	6,376		$	2.36		$	720
Workover and maintenance		12,805			3.26		4,105			1.52			8,700
Direct lease operating expense		54,233			13.80		33,965			12.56			20,268
Total lease operating expense		74,134			18.87		44,446			16.44			29,688
Production taxes		1,174			0.30		716			0.26			458
Gathering and transportation		3,395			0.86		801			0.29			2,594
DD&A		87,568			22.28		62,922			23.27			24,646
Accretion of asset retirement obligations		9,803			2.49		6,348			2.35			3,455
General and administrative expense		22,147			5.64		15,786			5.84			6,361
Loss (gain) on derivative financial instruments		4,371			1.11		(1,638	)		(0.61	)		6,009
Total costs and expenses	$	202,592		$	51.55	$	129,381		$	47.84		$	73,211
Other (income) expense
Other (income) expense – other	$	(15	)	$	—	$	9,533		$	3.53		$	(9,548	)
Interest expense		28,363			7.22		22,094			8.17			6,269
Total other (income) expense	$	28,348		$	7.22	$	31,627		$	11.70		$	(3,279	)

Costs and expenses increased $73 million in the second quarter of fiscal 2012. This increase in costs and expenses was due in part to the ExxonMobil Acquisition which increased production related expenses in the second quarter of fiscal 2012 coupled with higher general and administrative expense. Below is a discussion of costs and expenses.

DD&A expense increased $25 million principally as a result of increased production. The increase in DD&A expense as a result of improved production was $29 million which was partially offset by the effect of a lower DD&A rate resulting in a decrease of $4 million. Lease operating expense increased $30 million in the second quarter of fiscal 2012 compared to the second quarter of fiscal 2011. This increase is primarily due to higher direct lease operating and well workover and maintenance expense as a result of the ExxonMobil Acquisition. Gathering and transportation increased $3 million as a result of the gathering systems acquired in the ExxonMobil Acquisition.

Interest expense increased $6 million due to an increase in borrowings partially offset by a decrease in the overall interest rates. On a per unit of production basis, interest expense decreased 12%, from $8.17 per BOE to $7.22 per BOE.

Income Tax Expense

Income tax expense increased $11 million in the second quarter of fiscal 2012 compared to the second quarter of fiscal 2011. The effective income tax rate for the second quarter of fiscal 2012 decreased from the second quarter of fiscal 2011 from 15.5% to 11.4%.

Six Months Ended December 31, 2011 Compared With the Six Months Ended December 31, 2010.

Our consolidated income available for common stockholders for the six months ended December 31, 2011 was $156 million or $1.88 diluted income per common share (“per share”) as compared to consolidated loss attributable to common stockholders of $13.1 million or $0.23 diluted loss per share for the six months

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ended December 31, 2010. This improvement is primarily due to higher production volumes due to the ExxonMobil Acquisition coupled with higher crude oil prices partially offset by higher costs.

Price and Volume Variances

	Six Months Ended December 31,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	2011			2010
													(In thousands)
Price Variance(1)
Crude oil sales prices (per Bbl)	$	103.29		$	74.39		$	28.90			39	%	$	155,678
Natural gas sales prices (per Mcf)		5.01			5.93			(0.92	)		(16	)%		(12,684	)
Total price variance														142,994
Volume Variance
Crude oil sales volumes (MBbls)		5,385			3,527			1,858			53	%		138,217
Natural gas sales volumes (MMcf)		13,787			9,372			4,415			47	%		26,297
BOE sales volumes (MBOE)		7,683			5,089			2,594			51	%
Percent of BOE from crude oil		70	%		69	%
Total volume variance														164,514
Total price and volume variance													$	307,508

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

Revenue Variances

	Six Months Ended December 31,				Increase		Percent Increase
	2011		2010
			(In Thousands)
Crude oil	$	556,264	$	262,369	$	293,895		112	%
Natural gas		69,197		55,584		13,613		24	%
Total revenues	$	625,461	$	317,953	$	307,508		97	%

Revenues

Our consolidated revenues increased $308 million in the first six months of fiscal 2012 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to improved crude oil sales prices, higher crude oil and natural gas sales volumes as a result of the ExxonMobil Acquisition and the results of our drilling activity, partially offset by lower natural gas 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. Higher overall commodity prices increased revenues by $143 million in the first six months of fiscal 2012. Average natural gas prices, including a $1.41 realized gain per Mcf related to hedging activities, decreased $0.92 per Mcf during the first six months of fiscal 2012, resulting in decreased revenues of $13 million. Average crude oil prices, including a $0.08 realized gain per barrel related to hedging activities, increased $28.90 per barrel, resulting in increased revenues of $156 million. Commodity prices are affected by many factors that are outside of our control. Therefore, commodity prices we received during the first six months of fiscal 2012 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash from operating activities, potentially causing us to expend less on our capital program. Lower spending on our capital program could result in a reduction of the amount of production volumes we are able to produce. We cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

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Volume Variances

Sales volumes are another key driver that impact our earnings and net operating cash flow. Higher total sales volumes in the first six months of fiscal 2012 resulted in increased revenues of $165 million. Crude oil sales volumes increased 10.1 MBbls per day in the first six months of fiscal 2012, resulting in increased revenues of $138 million. Natural gas sales volumes increased 24 MMcf per day in the first six months of fiscal 2012, resulting in increased revenues of $26 million. The increase in crude oil and natural gas sales volumes in the first six months of fiscal 2012 was primarily due to the ExxonMobil Acquisition and to the success of our drilling program.

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

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

Costs and Expenses and Other (Income) Expense

	Six Months Ended December 31,												Increase (Decrease) Amount
	2011						2010
	Amount			Per BOE			Amount			Per BOE
	(In Thousands, except per unit amounts)
Costs and expenses
Lease operating expense
Insurance expense	$	14,558		$	1.89		$	12,519		$	2.46		$	2,039
Workover and maintenance		19,458			2.53			11,723			2.30			7,735
Direct lease operating expense		111,151			14.47			64,357			12.65			46,794
Total lease operating expense		145,167			18.89			88,599			17.41			56,568
Production taxes		3,348			0.44			1,410			0.28			1,938
Gathering and transportation		9,548			1.24			822			0.15			8,726
DD&A		172,371			22.44			116,999			22.99			55,372
Accretion of asset retirement obligations		19,491			2.54			12,322			2.42			7,169
General and administrative expense		41,468			5.40			34,383			6.76			7,085
Gain on derivative financial instruments		(6,001	)		(0.78	)		(2,776	)		(0.55	)		(3,225	)
Total costs and expenses	$	385,392		$	50.17		$	251,759		$	49.46		$	133,633
Other (income) expense
Other (income) expense – other	$	(24	)	$	—		$	9,523		$	1.87		$	(9,547	)
Interest expense		55,551			7.23			43,574			8.56			11,977
Total other (income) expense	$	55,527		$	7.23		$	53,097		$	10.43		$	2,430

Costs and expenses increased $134 million in the first six months of fiscal 2012. This increase in costs and expenses was due in part to the ExxonMobil Acquisition which increased production related expenses in the first six months of fiscal 2012 coupled with higher general and administrative expense. Below is a discussion of costs and expenses.

DD&A expense increased $55 million as a result of increased production which was partially offset by a lower DD&A rate. The lower DD&A rate was due in part to the addition of the lower cost ExxonMobil Acquisition reserves. The increase as a result of improved production was $59 million and the favorable impact of the lower DD&A rate was $4 million. Lease operating expense increased $57 million in the first six months of fiscal 2012 compared to the first six months of fiscal 2011. This increase is primarily due to higher workover and maintenance costs in the first six months of fiscal 2012 as a result of platform maintenance coupled with higher direct lease operating as a result of the ExxonMobil acquisition. Gathering and transportation increased $9 million as a result of the gathering systems acquired in the ExxonMobil Acquisition.

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General and administrative expense increased $7 million in the first six months of fiscal 2012 principally as a result of the higher compensation expense related to Phantom and Performance Units due to our rising common stock price partially offset by lower legal and other costs.

Other (income) expense increased $2 million in the first six months of fiscal 2012. This increase was primarily due to the items discussed below.

Higher interest expense of $12 million in comparing the first six months of fiscal 2012 to fiscal 2011 was due to an increase in borrowings partially offset by a decrease in the overall interest rates. This increase was partially offset by the Bridge Loan Commitment Fees of $4.5 million and the loss on the redemption of the 16% Second Lien Notes of $5.2 million in the first six months of fiscal 2011. On a per unit of production basis, interest expense decreased 16%, from $8.56 per BOE to $7.23 per BOE.

Income Tax Expense

Income tax expense increased $19 million in the first six months of fiscal 2012 compared to the first six months of fiscal 2011. The effective income tax rate for the first six months of fiscal 2012 decreased from the first six months of fiscal 2011 from 15.5% to 11.4%.

Liquidity and Capital Resources

Overview

As of December 31, 2011, we had approximately $79 million in cash and cash equivalents on hand and approximately $1,029 million in outstanding long-term debt obligations.

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 December 31, 2011, the principal balance of our revolving credit facility and outstanding tranches of senior notes and related maturity dates were as follows:

• Revolving credit facility — $28 million — Due December 2014;

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

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

In March 2011, the Office of National Resources Revenue (the “ONRR”) issued a letter stating that our Company qualifies for a supplemental bonding waiver. We still maintain approximately $24.5 million in bonds issued to third parties other than the ONRR 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.

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Our fiscal 2012 capital budget, excluding any potential acquisition and abandonment costs, is expected to range from $450 million to $500 million. We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from operations and borrowings under our revolving credit facility. We believe our available liquidity will be sufficient to meet our funding requirements through December 31, 2012. However, future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. There can be no assurance that cash flow from operations or other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. While we do not currently have a common share repurchase program in place, we may implement one in the future, which would impact our initial fiscal 2012 capital budget. If an acquisition opportunity arises, we also may seek to access public markets to issue additional debt and/or equity securities. Cash flows from operations were used primarily to fund exploration and development expenditures during the second quarter of fiscal 2012.

Operating Activities

Net cash provided by operating activities in the first six months of fiscal 2012 was $368 million as compared to cash provided of $77 million in the first six months of fiscal 2011. The increase was due in part to higher net commodity prices and production volumes, which was partially offset by higher production costs. The first six months of fiscal 2012 also included higher proceeds from sale of derivative instruments and higher nonproduction costs and expenses. Changes in operating assets and liabilities decreased $62 million primarily due to accounts payable and accrued liabilities.

Investing Activities

Our investments in properties were $245 million and $1,142 million for the six months ended December 31, 2011 and 2010, 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 revolving credit facility. If an acquisition opportunity arises, we may also access the capital markets to issue additional debt and/or equity securities. As of December 31, 2011, we had $491 million available for borrowing under our revolving credit facility. Our current borrowing base is $750 million as at December 31, 2011. Our next borrowing base redetermination is scheduled for the spring of 2012 utilizing our December 31, 2011 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, 2012. However, future cash flows are subject to a number of variables, including the level of production and commodity 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 used in financing activities was $81 million for the six months ended December 31, 2011 as compared to cash provided by financing activities of $1,089 million for the six months ended December 31, 2010. During the six months ended December 31, 2011 total repayment of debt net of proceeds from borrowings was $82 million. During the six months ended December 31, 2010, net of proceeds from borrowings was $573 million.

Available Credit

Credit markets in the United States and around the world have been constrained due to a lack of liquidity and confidence in a number of financial institutions during 2009, 2010 and more recently in 2011. Investors have sought perceived safe investments in securities of the United States government rather than individual entities. We may experience difficulty accessing the long-term credit markets should conditions return to levels prevailing in 2009 and early 2010. Additionally, constraints in the credit markets may increase the rates we are charged for utilizing these markets. Notwithstanding periodic weakness in the United States credit markets, we expect that our available liquidity is sufficient to meet our operating and capital requirements through December 31, 2012. 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.

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Contractual Obligations

Information about contractual obligations at December 31, 2011 did not change materially, other than as disclosed in Notes 5 and 14 to our accompanying unaudited consolidated financial statements included elsewhere in this Quarterly Report and from the disclosures in Item 7 of our 2011 Annual Report.

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 “Notes to Consolidated Financial Statements,” included in our 2011 Annual Report.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Note 2 “Recent Accounting Pronouncements” to our accompanying unaudited consolidated financial statements included elsewhere 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 2011 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 December 31, 2011, 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.

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With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options 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.

For a complete discussion of our open commodity derivatives as of December 31, 2011, please see Note 8 to our unaudited consolidated financial statements included elsewhere 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 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.

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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. 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 December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2011 Annual Report, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

ITEM 6. Exhibits

The following exhibits are filed as part of this report.

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
10.1	First Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 4, 2011	10.1 to the Company’s Form 8-K filed on October 4, 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

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SIGNATURES

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

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

Date: February 2, 2012

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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
10.1	First Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 4, 2011	10.1 to the Company’s Form 8-K filed on October 4, 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

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